Silica nanoparticles for crude oil recovery using carbon dioxide, and crude oil recovery method

ABSTRACT

An aqueous sol used in CO2 foam flooding, one of EOR flooding methods for recovering crude oil by injection into the oil reservoir of an onshore or offshore oil field, the aqueous sol increasing foam stability even over a substantial period of time, at high temperatures and pressures, and in salt water, thus improving crude oil recovery rate. The aqueous sol for increasing stability of froth or emulsion in a mixture containing carbon dioxide, water, and oil in CO2 foam flooding of EOR, the sol including silica particles having an average particle diameter of 1 to 100 nm as measured by dynamic light scattering and having surfaces at least partially coated with a silane compound having a hydrolyzable group, the silica particles serving as a dispersoid and dispersed in an aqueous solvent having a pH of 1.0 to 6.0 serving as a dispersion medium.

TECHNICAL FIELD

The present invention relates to an aqueous sol used in CO₂ foamflooding which is one of the enhanced oil recovery (hereinafter referredto as “EOR”) flooding methods for recovering crude oil by injection withCO₂ into an oil reservoir of onshore or offshore oil field.

BACKGROUND TECHNOLOGY

The recovery (extraction) of crude oil from an oil reservoir is carriedout in three-stages; i.e., primary, secondary, and tertiary recovery (orEOR (enhanced recovery)), wherein different recovery methods are used ineach of the stages.

The primary recovery method includes flush production, which uses theoriginal pressure and gravity within the oil reservoir, and alsoartificial lift, which uses an artificial oil extraction technique suchas a pumping. The crude oil recovery rate in the primary recovery stage,through combination of these methods is said to be maximum of only about20%. The secondary recovery method includes water flooding or reservoirpressure maintenance, wherein water or natural gas is injected tomaintain reservoir pressure and to increase oil production afterproduction decline in the primary recovery stage. Even with acombination of these primary and secondary recoveries, the crude oilrecovery rate is estimated to be about 40%, and the majority of crudeoil remains in the subsurface oil reservoir. Thus, the tertiary recoverymethod; i.e., the enhanced oil recovery method (EOR flooding), has beendeveloped for higher recovery of crude oil, and for recovery of morecrude oil from oil reservoirs wherein crude oil has already beenrecovered from easily recoverable pore spaces.

The EOR technology includes thermal flooding, gas flooding, microbialflooding, and chemical flooding. Among these, gas flooding (alsoreferred to as “miscible gas flooding”) forms a miscible state (mixingstate under supercritical pressure) between the injection gas (fluid)and oil, to thereby improve the recovery rate of crude oil remaining inmicropores of the reservoir rock. In gas flooding, for example,hydrocarbon gas, carbon dioxide (CO₂), nitrogen gas, or combustionexhaust gas generated during oil production is utilized for injection,and thus the gas extracted from the oil reservoir can be reused as is,and CO₂ in the exhaust gas emitted from, for example, refineries orpower plants can be recovered and used. Thus, gas flooding contributesto effective use of available resources while increasing the crude oilrecovery rate. In addition, gas flooding has received attention as atechnique that can contribute to a reduction in amount of greenhousegases emitted, i.e., a measure against global warming.

In gas flooding, injection gas tends to diffuse along larger pore spacesin the oil reservoir and is less likely to enter smaller pore spaces,due to high mobility of the injection gas. Thus, the water alternatinggas (WAG) injection process, wherein gas and water are injectedalternatingly, has also been applied to reduce the high mobility of theinjection gas.

CO₂ foam flooding, which is intended to improve the recovery efficiencythrough control of the mobility, has been proposed as a next-generationtechnology of the aforementioned CO₂ gas flooding method. In thisflooding method, the viscosity of injection fluid is increased byformation of CO₂ foam, and the comparative viscosity of crude oil (i.e.,the fluid to be replaced) is made relatively lower, to thereby improvethe mobility ratio and to improve the recovery efficiency of crude oilremaining in micropores of the reservoir rock.

For example, regarding CO₂ foam flooding, A. U. Rognmo (University ofBergen) et al., “Performance of Silica Nanoparticles in CO₂-Foam for EORand CCUS at Tough Reservoir Conditions”, Society of Petroleum Engineers(2018) SPE-191318-MS, Society of Petroleum Engineers, discloses atechnique using commercially available silane-modified silicananoparticles, and Shehab Alzobaidi (University of Texas at Austin) etal., “Carbon Dioxide-in-Brine Foams at High Temperatures and ExtremeSalinities Stabilized with Silica Nanoparticles”, Energy & Fuels 2017 3110680-10690, discloses a technique using silica nanoparticles whosesurfaces are grafted with ligands. JP 2005-526887 A discloses foam forenhancing oil recovery, the foam containing a foaming compositioncontaining surface-modified silica nanoparticles and a foaming agent(e.g., nitrogen gas). WO 2015/116332 discloses a method for recoveringcrude oil using emulsion stabilized with amphiphilic nanoparticlescontaining silica nanoparticles and metal nanoparticles.

SUMMARY OF THE INVENTION Problems to be Solved by the Invention

In crude oil recovery, a fluid (such as foam) injected into subsurfaceor undersea oil reservoirs is often produced after the elapse of severalmonths following injection. Thus, a demand has arisen for a fluid whichexhibits a crude oil recovery enhancement effect and which is stable forseveral tens of days to several months even under unusually harshconditions, such as exposure to high temperatures of 100° C. orthereabouts, high pressures of over 100 atm, and seawater or salt watercontaining sodium ions, calcium ions, chlorine ions, etc., at highconcentrations.

Although various techniques using, for example, silica nanoparticleshave been disclosed in CO₂ foam flooding of EOR as described above,there have been no reports on, for example, the stability of CO₂ foamparticularly at high pressure and temperature, or sols containing silicananoparticles.

The present invention is directed to an aqueous sol used in CO₂ foamflooding among EOR flooding methods for recovering crude oil byinjection into the oil reservoir of an onshore or offshore oil field.Specifically, an object of the present invention is to provide anaqueous sol that is used for increasing the stability of foam over along period of time, at high temperatures and pressures, and in saltwater, and for improving crude oil recovery rate.

Another object of the present invention is to provide a crude oilrecovery method using the aforementioned aqueous sol, and amanufacturing method for the aqueous sol.

Means for Solving the Problems

The present inventors have conducted extensive studies for solving theaforementioned problems, and as a result have found that an aqueous solwherein silica particles (serving as a dispersoid) having an averageparticle diameter of 1 to 100 nm and surfaces at least partially coatedwith a silane compound having a hydrolyzable group are dispersed in anaqueous solvent having a pH of 1.0 or more to 6.0 or less serving as adispersion medium can increase the stability of foam over a long periodof time, at high temperatures and pressures, and in salt water, whichleads to an improvement in crude oil recovery rate. The presentinvention has been accomplished on the basis of this finding.

Accordingly, a first aspect of the present invention is an aqueous solfor increasing the stability of froth or emulsion in a mixturecontaining carbon dioxide, water, and oil in CO₂ foam flooding ofenhanced oil recovery (EOR), the aqueous sol comprising:

-   -   silica particles having an average particle diameter of 1 to 100        nm as measured by dynamic light scattering and having surfaces        at least partially coated with a silane compound having a        hydrolyzable group, the silica particles serving as a dispersoid        and being dispersed in an aqueous solvent having a pH of 1.0 or        more to 6.0 or less serving as a dispersion medium.

A second aspect of the present invention is the aqueous sol according tothe first aspect, wherein the silane compound having a hydrolyzablegroup is a silane compound having an epoxy group or an organic groupproduced by hydrolysis of the epoxy group.

A third aspect of the present invention is the aqueous sol according tothe second aspect, wherein the epoxy group is a glycidyl group, acyclohexylepoxy group, or a combination of these.

A fourth aspect of the present invention is the aqueous sol according tothe first aspect, wherein the silane compound having a hydrolyzablegroup is a silane compound having an amino group.

A fifth aspect of the present invention is the aqueous sol according toany one of the first to fourth aspects, wherein the silane compoundhaving a hydrolyzable group further contains a second silane compoundhaving a hydrolyzable group.

A sixth aspect of the present invention is the aqueous sol according tothe fifth aspect, wherein the second silane compound having ahydrolyzable group is a silane compound having an organic groupcontaining a C₁₋₄₀ alkyl group, a C₆₋₄₀ aromatic ring group, or acombination of these.

A seventh aspect of the present invention is the aqueous sol accordingto any one of the first to sixth aspects, wherein the mass ratio of thesilane compound to the silica particles is 0.01 to 2.00:1.00 in thesilica particles having at least partially coated surfaces.

An eighth aspect of the present invention is the aqueous sol accordingto any one of the first to seventh aspects, wherein the aqueous sol hasno isoelectric point at a pH of 6 or less.

A ninth aspect of the present invention is the aqueous sol according toany one of the first to eighth aspects, wherein when the aqueous sol issubjected to a storage test at 80° C. for 30 days in an environmentcontaining sodium chloride, calcium chloride, and magnesium chloride asmain components and having a total salt concentration of 10,000 to230,000 ppm such that the silica concentration is 1.0% by mass, thedifference between the average particle diameter as measured by dynamiclight scattering after the test and the average particle diameter beforethe test is 200 nm or less in the aqueous sol.

A tenth aspect of the present invention is the aqueous sol according toany one of the first to ninth aspects, wherein the aqueous sol has a pHof 1.0 or more to 6.0 or less upon coating of the silica particles withthe silane compound having a hydrolyzable group in the aqueous medium,and when the aqueous sol stored at a pH of 1.0 or more to 6.0 or less issubjected to a storage test at a pH of 5.0 or more to 8.0 or less at 80°C. for 30 days in an environment containing sodium chloride, calciumchloride, and magnesium chloride as main components and having a totalsalt concentration of 10,000 to 230,000 ppm such that the silicaconcentration is 1.0% by mass, the difference between the averageparticle diameter as measured by dynamic light scattering after the testand the average particle diameter before the test is 200 nm or less inthe aqueous sol.

An eleventh aspect of the present invention is the aqueous sol accordingto any one of the first to tenth aspects, wherein the froth or theemulsion is stable at a temperature of 30 to 120° C. and a pressure of70 to 400 atm.

A twelfth aspect of the present invention is a crude oil recovery methodfor recovering crude oil from a subsurface hydrocarbon-containingreservoir, the method comprising:

-   -   step (a): a step of injecting the aqueous sol according to any        one of the first to eleventh aspects, water and carbon dioxide        each alternatingly or simultaneously into a subsurface oil        reservoir; and    -   step (b): a step by which oil is recovered to the surface from        oil production well drilled into subsurface oil reservoir.

A thirteenth aspect of the present invention is the crude oil recoverymethod according to the twelfth aspect, wherein the step (a) is a stepof injecting the aqueous sol and water, and carbon dioxide alternatinglyinto the subsurface oil reservoir.

A fourteenth aspect of the present invention is the crude oil recoverymethod according to the twelfth or thirteenth aspect, wherein theinjection in the step (a) is performed at a temperature of 30 to 120° C.and a pressure of 70 to 400 atm.

A fifteenth aspect of the present invention is the crude oil recoverymethod according to any one of the twelfth to fourteenth aspects,wherein the subsurface oil reservoir contains sandstone.

A sixteenth aspect of the present invention is the crude oil recoverymethod according to any one of the twelfth to fourteenth aspects,wherein the subsurface oil reservoir contains carbonate rocks.

A seventeenth aspect of the present invention is a manufacturing methodfor the aqueous sol according to any one of the first to eleventhaspects, the aqueous sol containing, as a dispersoid, silica particleshaving surfaces at least partially coated with a silane compound havinga hydrolyzable group, the manufacturing method comprising a step ofmixing an aqueous sol of unmodified colloidal silica with a silanecompound having a hydrolyzable group so that the mass ratio of thesilane compound to silica particles contained in the aqueous sol is 0.01to 2:1.00, and treating the mixture at a pH of 1 or more to 6 or lessfor 0.1 hours to 20 hours.

An eighteenth aspect of the present invention is the manufacturingmethod according to the seventeenth aspect, wherein the step of mixingthe aqueous sol of unmodified colloidal silica with the silane compoundhaving a hydrolyzable group and treating the mixture is performed at 50to 100° C.

Effects of the Invention

The aqueous sol of the present invention can stably form and maintainfine CO₂ foam over a long period of time at high temperatures (30 to120° C.), high pressures (70 to 400 atm), and different saltconcentrations (10,000 to 230,000 ppm).

The formation of CO₂ foam exhibiting excellent long-term stability andsalt resistance increases the viscosity of the fluid (CO₂ foam) to beinjected into the subsurface oil reservoir. Thus, it can be expectedthat the fluid penetrates into pores of the reservoir rock (includingpores that have been hitherto difficult to penetrate), thereby improvingthe recovery efficiency of crude oil in the rock and enabling recoveryof crude oil at a higher rate.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows the results of measurement of the zeta potentials of theaqueous sols (aqueous silica sols subjected to surface treatment with asilane compound) prepared in Examples 1 and 2 at different pH valuesfrom pH 2 or more to pH 10 or less.

FIG. 2 shows a change in average particle diameter as measured bydynamic light scattering (DLS average particle diameter: nm) during atest for stability against salt water (storage at 80° C., low saltconcentration: 35,000 ppm) of the aqueous sols of Example 1 andComparative Example 1.

FIG. 3 shows a change in average particle diameter as measured bydynamic light scattering (DLS average particle diameter: nm) during atest for stability against salt water (storage at 80° C., medium saltconcentration: 175,000 ppm) of the aqueous sols of Example 1 andComparative Example 1.

FIG. 4 shows a change in average particle diameter as measured bydynamic light scattering (DLS average particle diameter: nm) during atest for stability against salt water (storage at 80° C., high saltconcentration: 229,000 ppm) of the aqueous sols of Example 1 andComparative Example 1.

FIG. 5 shows the structure of an apparatus used in a foamability test.

FIG. 6 shows the results of a foamability test of the aqueous sols ofExamples 1 and 2 and Comparative Example 1.

FIG. 7 shows the results of a foamability test of the aqueous sols ofExamples 3 and 4 and Comparative Example 1.

FIG. 8 is a photograph showing the results of a long-term stability testof froth or emulsion 30 minutes, one day, three days, and seven daysafter the termination of stirring in the foamability test of the aqueoussols of Examples 1 and 2.

FIG. 9 is an optical microscope photograph of W/O emulsion formed at apressure of 100 atm by addition of a water-soluble dye to a salt watersample (salt concentration: 229,000 ppm) containing the aqueous sol ofExample 1 (silica concentration: 1.0% by mass).

FIG. 10 is an optical microscope photograph of O/W emulsion formed at apressure of 100 atm by addition of a water-soluble dye to a salt watersample (salt concentration: 229,000 ppm) containing the aqueous sol ofExample 1 (silica concentration: 1.0% by mass).

FIG. 11 is an optical microscope photograph of froth formed at apressure of 300 atm by addition of a water-soluble dye to a salt watersample (salt concentration: 229,000 ppm) containing the aqueous sol ofExample 1 (silica concentration: 1.0% by mass).

FIG. 12 is a schematic view of W/0 emulsion formed at a pressure of 100atm by addition of a water-soluble dye to a salt water sample (saltconcentration: 229,000 ppm) containing the aqueous sol of Example 1(silica concentration: 1.0% by mass).

FIG. 13 is a schematic view of O/W emulsion formed at a pressure of 100atm by addition of a water-soluble dye to a salt water sample (saltconcentration: 229,000 ppm) containing the aqueous sol of Example 1(silica concentration: 1.0% by mass).

FIG. 14 is a schematic view of froth formed at a pressure of 300 atm byaddition of a water-soluble dye to a salt water sample (saltconcentration: 229,000 ppm) containing the aqueous sol of Example 1(silica concentration: 1.0% by mass).

FIG. 15 is a photograph showing the appearances of (a) sandstone (BereaSandstone (BSS)) and (b) carbonate rocks (Indiana 200md (IN 200md)) usedfor evaluation of crude oil recovery, and the results of observation ofthe surface profiles of these cores (scanning electron microscopephotographs (magnification: 500)).

FIG. 16 shows the relationship between the air permeability and porosityof a carbonate rock sample.

FIG. 17 shows the pipe and equipment layout of a core flow testapparatus used for evaluation of crude oil recovery.

FIG. 18 shows the amount (%) of crude oil (vertical axis) recovered frompores of a sandstone (BSS) core sample with respect to the amount ofinjection (horizontal axis) of a fluid (salt water containing theaqueous sol of Example 1 or 2 (silica concentration: 1.0% by mass),carbon dioxide) when the total rock pore volume of the core sample istaken as 1.0.

FIG. 19 shows the amount (%) of crude oil (vertical axis) recovered frompores of a carbonate rock (IN 200md) core sample with respect to theamount of injection (horizontal axis) of a fluid (salt water containingthe aqueous sol (silica concentration: 1.0% by mass), carbon dioxide)when the total rock pore volume of the core sample is taken as 1.0.

FIG. 20 is a photograph of a sample prepared by using the aqueous sol ofExample 1 (medium salt concentration: 175,000 ppm, silica concentration:1.0% by mass) (pH 6.3) (FIG. 20(a)), and a sample prepared by using theaqueous sol of Comparative Example 1 (medium salt concentration: 175,000ppm, silica concentration: 1.0% by mass) (pH 7.2) (FIG. 20(b)), whereinthe photograph shows the states of the samples after being stored at 80°C. for seven days.

FIG. 21 shows the structure of an apparatus used in a test fordetermining presence of pore blockage within the core.

FIG. 22 shows the injection differential pressure (left vertical axis)and the amount (cc) of salt water (containing the aqueous sol) (rightvertical axis) recovered from pores of a sandstone (BSS) core samplewith respect to the amount of injection (horizontal axis) of a fluid(stored salt water sample (medium salt concentration) containing theaqueous sol (silica concentration: 1.0% by mass), carbon dioxide) whenthe total rock pore volume of the core sample is taken as 1.0 in a testfor determining presence of pore blockage within the core using theaqueous sol of Example 1.

FIG. 23 is a photograph showing formation of froth in the recoveredfluid in the test for determining presence of pore blockage within thecore using the aqueous sol of Example 1

FIG. 24 shows the fluid injection pressure (vertical axis) with respectto the injection time (horizontal axis) in the case of continuousinjection of a fluid (stored salt water sample (medium saltconcentration) containing the aqueous sol (silica concentration: 1.0% bymass), carbon dioxide) when the total rock pore volume of a sandstone(BSS) core sample is taken as 1.0 in a test for determining presence ofpore blockage within the core using the aqueous sol of Example 2.

FIG. 25 shows the injection differential pressure (left vertical axis)and the amount (cc) of salt water (containing the aqueous sol) (rightvertical axis) recovered from pores of a sandstone (BSS) core samplewith respect to the amount of injection (horizontal axis) of a fluid(stored salt water sample (medium salt concentration) containing theaqueous sol (silica concentration: 1.0% by mass), carbon dioxide) whenthe total rock pore volume of the core sample is taken as 1.0 in a testfor determining presence of pore blockage within the core using theaqueous sol of Comparative Example 1.

FIG. 26 shows the fluid injection pressure (vertical axis) with respectto the injection time (horizontal axis) in the case of continuousinjection in the test for determining presence of pore blockage withinthe core using the aqueous sol of Comparative Example 1.

FIG. 27 is a photograph of a pipe of an apparatus used in the test fordetermining presence of pore blockage within the core using the aqueoussol of Comparative Example 1, wherein the photograph shows the state ofthe pipe after the test (formation of a gelatinized silica component).

MODES FOR CARRYING OUT THE INVENTION

The present invention is directed to an aqueous sol for increasing thestability of froth or emulsion in a fluid in CO₂ foam flooding ofenhanced oil recovery (EOR). The aqueous sol of the present inventioncan contribute to formation and stabilization of froth or emulsionthrough contact of the aqueous sol with water (including salt water,seawater, etc.) and carbon dioxide, and through contact of these withcrude oil.

The term “froth” as used herein refers to “foam” composed of numerousbubbles, wherein each bubble has a diameter of about several μm toseveral hundreds of μm.

In the case of emulsion, each droplet generally has a diameter of about0.1 μm to several hundreds of μm.

<Aqueous Sol>

In general, an aqueous sol is a colloidal dispersion system containingan aqueous solvent serving as a dispersing medium and colloidalparticles serving as a dispersoid. The present invention is particularlydirected to an aqueous sol wherein the dispersing medium is an aqueousmedium (water) having an acidic pH, and the dispersoid is silicaparticles subjected to surface treatment with a specific functionalgroup. Specifically, the present invention is directed to an aqueous solwherein the dispersoid is silica particles having surfaces at leastpartially coated with a silane compound having a hydrolyzable group(hereinafter may be simply referred to as “silane compound”)(hereinafter the silica particles may be referred to as “silicaparticles subjected to surface treatment with a silane compound” or“surface-treated silica particles”), and the dispersion medium is anaqueous solvent having a pH of 1.0 or more to 6.0 or less.

The phrase “silica particles having surfaces at least partially coatedwith a silane compound having a hydrolyzable group” as used hereinrefers to a state where the silane compound having a hydrolyzable groupis bonded to at least a portion of the surfaces of silica particles”;specifically includes a state where the silane compound covers theentire surfaces of silica particles, a state where the silane compoundcovers a portion of the surfaces of silica particles, and a state wherethe silane compound is bonded to the surfaces of silica particles.

The silica particles (surface-treated silica particles) contained in theaqueous sol of the present invention can be evaluated for their averageparticle diameter (DLS average particle diameter) and dispersion stateby dynamic light scattering.

The DLS average particle diameter corresponds to the average of thediameters of secondary particles (diameters of dispersed particles). Itis said that the DLS average particle diameter of completely dispersedparticles is about twice the average primary particle diameter (i.e.,specific surface area diameter as measured by the nitrogen gasadsorption method (BET method) or the Sears method, corresponding to theaverage of primary particle diameters). Thus, the measurement of the DLSaverage particle diameter can determine whether the colloidal particles(surface-treated silica particles in the present invention) contained inthe aqueous sol are in a dispersed state or in an aggregated state.Specifically, it can be determined that a larger DLS average particlediameter indicates an aggregated state of the colloidal particlescontained in the aqueous sol.

In the present invention, the surface-treated silica particles containedin the aqueous sol may have an average particle diameter (DLS particlediameter) of 1 to 100 nm, or 1 to 50 nm, or 3 to 30 nm, or 5 to 15 nm.The particles having a DLS average particle diameter of more than 1 nmdo not aggregate in the aqueous sol and remain stable therein, whereasthe particles having a DLS average particle diameter of less than 100 nmenable the sol to readily penetrate into pores of sandstone or carbonaterocks present in the subsurface oil field reservoir, resulting inimproved crude oil recovery rate.

In the surface-treated silica particles contained in the aqueous sol,the mass ratio of the silane compound to the silica particles is, forexample, 0.01 to 2.00:1.00, or 0.30 to 2.00:1.00, or 0.33 to 2.00:1.00,or 0.33 to 1.00:1.00.

When the amount of the silane compound is 0.01 parts by mass or more(preferably 0.30 parts by mass or more) relative to 1.00 parts by massof the silica particles contained in the aqueous sol, the aqueous solcan be expected to have favorable salt resistance. However, when theamount of the silane compound is adjusted to 2.00 parts by mass or more,an effect commensurate with an increase in the amount cannot beobtained.

In the aforementioned aqueous sol, the concentration of thesurface-treated silica particles (solid content concentration) may be,for example, 1 to 40% by mass.

Preferably, the aqueous sol of the present invention has no isoelectricpoint at a pH of 6 or less, for example, a pH range of 1 or more to 6 orless. In such a case, the aqueous sol can be expected not to aggregatebut to remain stable.

In general, the salt concentration of seawater is about 30,000 ppm to40,000 ppm, the salt concentration of oil and gas fields in Japan isabout 10,000 ppm to 50,000 ppm, and the salt concentration of formationwater overseas (for example, in the Abu Dhabi carbonate rock oil field)is about 160,000 ppm, etc. In view of injection of the aqueous sol ofthe present invention into an oil reservoir in an onshore or offshoreoil field, the aqueous sol desirably exhibits high salt resistance in anenvironment having a salt concentration of about 10,000 ppm(corresponding to 1.0% by mass) to over 200,000 ppm; specifically, it isdesirable that the silica particles contained in the aqueous sol do notaggregate or gelate and remain in a dispersed state in theaforementioned environment.

In the present invention, the salt resistance (salt water stability) ofthe aqueous sol can be evaluated by a salt resistance test wherein theaqueous sol is stored at a pH of 5.0 or more to 8.0 or less and 80° C.for 30 days in an environment containing sodium chloride, calciumchloride, and magnesium chloride as main components and having a totalsalt concentration of 10,000 to 230,000 ppm such that the silicaconcentration is 1.0% by mass. When a change in the average particlediameter of the aqueous sol as measured by dynamic light scattering issmall before and after this test, the silica particles contained in theaqueous sol can be evaluated to maintain their dispersed state. However,when the aqueous sol exhibits poor salt resistance, the DLS averageparticle diameter becomes very large after the salt resistance test,which reflects the aggregated state of the silica particles contained inthe sol.

In the present invention, the aqueous sol can be determined to have goodsalt resistance when the average particle diameter measured by dynamiclight scattering after the aforementioned salt resistance test differsby 200 nm or less from the average particle diameter before the test. Inparticular, when the difference in DLS average particle diameter betweenbefore and after the test is 200 nm or less (e.g., 160 nm or less), theaqueous sol can be determined to have very good salt resistance withoutalteration (aggregation or gelation) of the silica sol.

The silica particles contained in the aqueous sol of the presentinvention can maintain stable froth or emulsion form in the presence ofwater, oil, and carbon dioxide at a temperature of 30 to 120° C. and apressure of 70 to 400 atm. The term “stable” as used herein refers tothe case where the froth or the emulsion does not disintegrate orseparate. The present inventors confirmed that when froth or emulsion isformed for several hours under static conditions, the foam or theemulsion stably maintains its form for several days.

Carbon dioxide becomes supercritical under conditions of 31.1° C. and72.8 atm or higher. In the present invention, the oil in rock pores isdisplaced by water (containing the silica particles), oil, and carbondioxide in the form of froth or emulsion. In this case, the carbondioxide may be in a homogeneous supercritical state or in a gas orliquid phase state.

The aforementioned aqueous sol is prepared by mixing a silane compoundhaving a hydrolyzable group with an (unmodified) aqueous silica sol, andthen subjecting the mixture to thermal treatment as described below. Theaqueous silica sol and the silane compound having a hydrolyzable group,which form the aqueous sol, will be described below in detail.

<Aqueous Silica Sol>

The aqueous silica sol (unmodified silica sol), which forms the aqueoussol of the present invention, is an aqueous silica sol containingcolloidal silica as a dispersoid, and can be produced by any knownmethod using water glass (aqueous sodium silicate solution) as a rawmaterial.

The average particle diameter of the aqueous silica sol indicates theaverage particle diameter of the colloidal silica particles serving as adispersoid. Unless otherwise specified, the average particle diameterrefers to the specific surface area diameter as measured by the nitrogengas adsorption method (BET method) or the particle diameter as measuredby the Sears method.

The specific surface area diameter (average particle diameter (specificsurface area diameter) D (nm)) as measured by the nitrogen gasadsorption method (BET method) is given by the following formula: D(nm)=2720/S wherein S represents the specific surface area (m²/g) asmeasured by the nitrogen gas adsorption method.

The particle diameter as measured by the Sears method corresponds to theaverage particle diameter measured according to the literature: G. W.Sears, Anal. Chem. 28 (12), p. 1981, 1956 (Rapid Method forDetermination of Colloidal Silica Particle Diameter). Specifically, theparticle diameter corresponds to the equivalent diameter (specificsurface area diameter) calculated from the specific surface area ofcolloidal silica determined from the amount of 0.1N—NaOH required fortitration, from pH 4 or more to pH 9 or less, of colloidal silicaequivalent to 1.5 g of SiO₂.

In the present invention, the average particle diameter of the aqueoussilica sol (colloidal silica particles) as measured by the nitrogen gasadsorption method (BET method) or the Sears method may be, for example,1 to 100 nm, or 1 to 50 nm, or 3 to 30 nm, or 5 to 15 nm.

The aforementioned aqueous silica sol may be a commercially availableproduct. An aqueous silica sol having a silica concentration of 5 to 50%by mass is generally commercially available. Such a product is preferredsince it is readily available.

The aqueous silica sol may be an alkaline aqueous silica sol or anacidic aqueous silica sol. However, an acidic aqueous silica sol havinga pH of 1.0 or more to 6.0 or less is preferably used, since such anaqueous silica sol enables production of an aqueous sol exhibitingexcellent salt resistance (no aggregation).

Examples of the commercially available acidic aqueous silica sol includeSnowtex (registered trademark) ST-OXS, ST-OS, and ST-O (available fromNissan Chemical Corporation).

The aqueous silica sol used for the aqueous sol may have a silica (SiO₂)concentration of, for example, 1 to 40% by mass.

<Silane Compound>

The silane compound used for the surface treatment of the aforementionedaqueous silica sol is a silane compound having a hydrolyzable group.Examples of the hydrolyzable group include an alkoxy group, an acyloxygroup, and a halogen group.

In particular, the hydrolyzable group is preferably an alkoxy group suchas methoxy group or ethoxy group. For example, a silane compound havinga methoxy group as a hydrolyzable group is preferably used.

The aforementioned silane compound having a hydrolyzable group may be asilane compound having, besides the hydrolyzable group, an epoxy groupor an organic group produced by hydrolysis of the epoxy group. The epoxygroup may be a glycidyl group, a cyclohexylepoxy group, or a combinationof these. As described below, the aforementioned silane compound havinga hydrolyzable group may be a silane compound having, besides thehydrolyzable group, an oxetane ring instead of an epoxy group.

Examples of the silane compound having the epoxy group (and ahydrolyzable group) include 3-glycidoxypropyltrimethoxysilane,3-glycidoxypropyltriethoxysilane,3-glycidoxypropylmethyldimethoxysilane,3-glycidoxypropylmethyldiethoxysilane,3-(3,4-epoxycyclohexyl)propyltrimethoxysilane,3-(3,4-epoxycyclohexyl)propyltriethoxysilane,2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane,2-(3,4-epoxycyclohexyl)ethyltriethoxysilane,1-(3,4-epoxycyclohexyl)methyltrimethoxysilane, and1-(3,4-epoxycyclohexyl)methyltriethoxysilane. These silane compounds maybe used alone or in combination of two or more species.

As described above, the silane compound having an epoxy group may bereplaced by a silane compound having an oxetane ring. Examples of thesilane compound having an oxetane ring include[(3-ethyl-3-oxetanyl)methoxy]propyltrimethoxysilane and[(3-ethyl-3-oxetanyl)methoxy]propyltriethoxysilane.

The aforementioned silane compound having a hydrolyzable group may be asilane compound having an amino group besides the hydrolyzable group.

Examples of the silane compound having an amino group (and ahydrolyzable group) includeN-2-(aminoethyl)-3-aminopropylmethyldimethoxysilane,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-aminopropyltrichlorosilane, 3-aminopropyltrimethoxysilane,3-aminopropyltriethoxysilane, 3-aminopropylmethyldimethoxysilane,3-aminopropylmethyldiethoxysilane,3-triethoxysilyl-N-(1,3-dimethyl-butylidene)propylamine,N-phenyl-3-aminopropyltrimethoxysilane, andN-phenyl-3-aminopropyltriethoxysilane. These silane compounds may beused alone or in combination of two or more species.

In the present invention, the silane compound used for the surfacetreatment of the aforementioned aqueous silica sol may further contain asecond silane compound having a hydrolyzable group besides theaforementioned silane compound having a hydrolyzable group (i.e., thesilane compound having an epoxy group or an organic group produced byhydrolysis of the epoxy group, or the silane compound having an aminogroup).

The second silane compound having a hydrolyzable group may be a silanecompound having an organic group containing a C₁₋₄₀ alkyl group, a C₆₋₄₀aromatic ring group, or a combination of these.

Examples of the silane having the aforementioned hydrolyzable group andhaving a C₁₋₄₀ alkyl group include alkoxysilanes, such asmethyltrimethoxysilane, methyltriethoxysilane, dimethyldimethoxysilane,dimethyldiethoxysilane, trimethylmethoxysilane, ethyltrimethoxysilane,ethyltriethoxysilane, n-propyltrimethoxysilane, n-propyltriethoxysilane,isobutyltrimethoxysilane, isobutyltriethoxysilane,n-hexyltrimethoxysilane, n-hexyltriethoxysilane,cyclohexylmethyldimethoxysilane, n-octyltriethoxysilane, andn-decyltrimethoxysilane. These silane compounds may be used alone or incombination of two or more species.

Examples of the silane having the aforementioned hydrolyzable group andhaving a C₆₋₄₀ aromatic ring group include phenyltrimethoxysilane,phenyltriethoxysilane, diphenyldimethoxysilane, anddiphenyldiethoxysilane.

The use of the second silane compound having a hydrolyzable groups incombination can be expected to further enhance the effect of stabilizingfroth or emulsion in the liquid in CO₂ foam flooding.

The second silane compound having a hydrolyzable group is preferablyused in combination particularly with a silane compound having ahydrolyzable group containing an amino group.

In the present invention, the surfaces of silica particles are treated(modified) by using, as an essential material, the silane compoundhaving a hydrolyzable group and having an epoxy group or an organicgroup produced by hydrolysis of the epoxy group or the silane compoundhaving an amino group (the first silane compound), and by using, ifdesired, the silane compound having a hydrolyzable group and having anorganic group containing a C₁₋₄₀ alkyl group, a C₆₋₄₀ aromatic ringgroup, or a combination of these (the second silane compound). The ratioby mole of the first silane compound to the second silane compound inthe entire silane compound may be 1.00:0 to 3.00 or 1.00:0 to 1.00.

In particular, the silane compound used for the surface treatment of theaforementioned aqueous silica sol may be, for example,3-glycidoxypropyltrimethoxysilane, 3-glycidoxypropyltriethoxysilane, acombination of 3-glycidoxypropyltrimethoxysilane with2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane, or a combination of3-aminopropyltriethoxysilane with phenyltrimethoxysilane.

The aforementioned silane compound may be a commercially availableproduct. Examples of the commercially available product include tradename KBM-403 (3-glycidoxypropyltrimethoxysilane), KBE-403(3-glycidoxypropyltriethoxysilane), KBM-303(2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane), KBE-903(3-aminopropyltriethoxysilane), and KBM-103 (phenyltrimethoxysilane),which are available from Shin-Etsu Chemical Co., Ltd.

The present invention involves the use of silane particles havingsurfaces bonded with a silane having an organic functional group, whichare prepared by treating (coating) the surfaces of silica particlescontained in an aqueous silica sol with a silane having a hydrolyzablegroup. In the present invention, an important factor in salt resistanceis a combination of the pH of an aqueous silica sol as a raw materialand the aforementioned hydrolyzable group. When an acidic aqueous silicasol is used as a raw material, the hydrolyzable group of theaforementioned silane may be a methoxy group or an ethoxy group, each ofwhich provides favorable effects.

When an alkaline aqueous silica sol is used as a raw material, gelationis likely to proceed during production of the aqueous sol if thehydrolyzable group of the aforementioned silane is a methoxy group, orsalt water resistance is lowered if the hydrolyzable group is an ethoxygroup. When an alkaline aqueous silica sol is used and coated with asilane having an ethoxy group as a hydrolyzable group, salt waterresistance is lowered even if the pH is then made acidic.

<Surface Treatment Method (Manufacturing Method for Aqueous Sol)>

The silica particles subjected to surface treatment with a silanecompound can be prepared by adding the aforementioned silane compoundhaving a hydrolyzable group to the aforementioned aqueous silica sol(preferably, an acidic aqueous silica sol having a pH of 1.0 or more to6.0 or less), and then subjecting the mixture to thermal treatment at,for example, 50 to 100° C. for one hour to 20 hours. In this case, thesilane compound having a hydrolyzable group may be added to the aqueoussilica sol so that the mass ratio of the silane compound to the silicaparticles (silica solid content) in the aqueous silica sol is asfollows: for example, the mass ratio of the silane compound to thesilica particles of 0.01 to 2.00:1.00, or 0.30 to 2.00:1.00, or 0.33 to2.00:1.00, or 0.33 to 1.00:1.00.

When the thermal treatment temperature is lower than 50° C., the rate ofpartial hydrolysis of the hydrolyzable group is reduced, and thus thesurface treatment efficiency is lowered, whereas when the thermaltreatment temperature is higher than 100° C., dry silica gel isgenerated, which is not desirable.

When the thermal treatment time is less than one hour, the hydrolysisreaction of the silane compound having a hydrolyzable group proceedsinsufficiently. Meanwhile, even when the thermal treatment time islonger than 20 hours, the hydrolysis reaction of the silane compoundbecomes almost saturated, and thus the heating time need not be longer.The phrase “silica particles coated with a silane compound” encompassesthe case where hydrolyzable groups are completely hydrolyzed, and thesilica particles are coated with siloxane bonds, and the case where somehydrolyzable groups remain unreacted and the other hydrolyzable groupsare hydrolyzed, and the silica particles are with siloxane bonds.

The amount of surface treatment (coating) with the silane compoundhaving a hydrolyzable group; i.e., the number of silane compoundmolecules bonded to the silica particle surface is preferably, forexample, 0.01 to 5 or 1 to 5 per nm² of the silica particle surface.

The resultant aqueous sol containing, as a dispersoid, silica particlessubjected to surface treatment with the silane compound corresponds toan aqueous sol dispersed in an aqueous solvent having a pH of 1.0 ormore to 6.0 or less; i.e., an aqueous sol stored at a pH of 1.0 or moreto 6.0 or less.

Surface-treated silica particles may be prepared by using an alkalineaqueous silica sol (pH 8 or higher), and adding a silane compound havinga hydrolyzable group to the aqueous silica sol in the same manner asdescribed above. However, an aqueous sol containing surface-treatedsilica particles dispersed in an aqueous medium prepared by using analkaline aqueous silica sol as a raw material requires attention, sincethe average particle diameter as measured by dynamic light scatteringincreases significantly after the salt resistance test described above;i.e., the silica particles are likely to aggregate and to be lessstable. When surface-treated silica particles are prepared underalkaline conditions, the aqueous sol wherein the particles are dispersedis confirmed to exhibit poor foamability in a mixture system of water,carbon dioxide, and a crude oil substitute (hydrocarbon (decane)). Thus,the aqueous sol is less likely to be effective in crude oil recovery bycarbon dioxide foam.

When an aqueous silica sol (aqueous sol) containing surface-treatedsilica particles prepared under alkaline conditions is made acidic with,for example, hydrochloric acid (e.g., pH 1.0 or more to 6.0 or less) tothereby yield an acidic aqueous silica sol (aqueous sol), the averageparticle diameter as measured by dynamic light scattering increasesafter the aforementioned salt resistance test, and the silica particlesaggregate and exhibit lowered stability. This acidic aqueous silica solalso exhibits poor foamability in a mixture system of water, carbondioxide, and a crude oil substitute (decane). Rock pores that contributeto fluid flow are considered to have a diameter of several μm or more.Thus, conceivably, the aggregated and gelated aqueous silica sol isdifficult to pass through rock pores of several μm sufficiently in thecore flood test. Therefore, the aforementioned alkaline aqueous silicasol (aqueous sol) subjected to surface treatment with a silane compoundunder alkaline conditions, or the acidic aqueous silica sol (aqueoussol) prepared from the alkaline aqueous silica sol is not suitable forcrude oil recovery in the present invention.

<Crude Oil Recovery Method>

The aqueous sol of the present invention can be used to recover crudeoil from a subsurface hydrocarbon-containing reservoir through, forexample, a procedure including step (a): a step of injecting the aqueoussol of the present invention, water, and carbon dioxide alternatingly orsimultaneously into the subsurface oil reservoir, and step (b): a stepby which oil is recovered to the surface from oil production welldrilled into subsurface oil reservoir.

The water to be injected in the step (a) may be salt water containingchlorine ions and sodium ions, calcium ions, magnesium ions, etc., ormay be seawater (for example, when the aqueous sol is assumed to be usedin oil reservoirs in offshore oil fields). No particular limitation isimposed on the salt concentration of such salt water or seawater, butthe salt concentration is generally about 10,000 to 230,000 ppm asdescribed above.

Upon injection, the mass ratio of the surface-treated silica particlescontained in the aqueous sol to water (or salt water, seawater) may be,for example, about 1:3 to 1,000, and the ratio by volume of water (orsalt water, seawater) to carbon dioxide may be, for example, about1:0.01 to 100.

Preferably, the injection pressure is equal to or higher than thenatural injection pressure by the gravity of a fluid from an injectionwell, and equal to or lower than the initial pressure of the targetreservoir or the stratum failure pressure of cap rock, whichever ishigher.

The injection step can be performed, for example, at a temperature of 30to 120° C. and a pressure of 70 to 400 atm.

The step (a) may be, for example, a step of injecting the aqueous soland water, and carbon dioxide alternatingly into the subsurface oilreservoir. The carbon dioxide to be injected may be supercritical carbondioxide or liquid carbon dioxide.

In the step (a), the aqueous sol or water may contain an optionalcomponent used for crude oil recovery. Examples of the optionalcomponent include, but are not limited to, a surfactant, a thickener, anoxygen scavenger, a corrosion inhibitor, an algaecide, a biocide, and ascale inhibitor.

No particular limitation is imposed on the subsurface oil reservoirtargeted by the crude oil recovery method, and the target reservoir maybe, for example, a reservoir containing sandstone or a reservoircontaining carbonate rocks.

In the present invention, the aqueous sol, water, and carbon dioxide areinjected into the formation rock so that the zeta potentials of thesilica particles in the aqueous sol and the formation rock are negativeor positive each other. This can prevent aggregation of the silicaparticles in rock pores, which is preferable for the formation andmaintenance of stable CO₂ foam and an improvement in crude oil recoveryefficiency on the basis thereof.

In the present invention, liquid carbon dioxide injected into thesubsurface oil reservoir forms CO₂ foam therein. This probably leads toan increase in the viscosity of the mixture containing the aqueous sol,water, and carbon dioxide, and enhances the recovery of oil in rockpores by the fluid having increased viscosity. The viscosity of thefluid formed of the mixture is preferably, for example, 1 cP to 100 cP,or 1 cP to 50 cP.

The step (a) is followed by the step (b): a step by which oil isrecovered to the surface from oil production well drilled intosubsurface oil reservoir.

EXAMPLES

(The following apparatuses were used for analysis in Examples andComparative Examples.)

pH: Measured with a pH meter (available from DKK-TOA CORPORATION).

Viscosity: Measured with Ostwald viscometer (available from AS ONECORPORATION).

Average primary particle diameter as measured by the nitrogen gasadsorption method (BET method): An aqueous silica sol was dried and theresultant silica solid was pulverized, and then the pulverized productwas further dried to yield silica powder. The average primary particlediameter was calculated on the basis of the specific surface area of thesilica powder determined with a specific surface area measuring deviceMonosorb (available from Quantachrome Instruments).

Average particle diameter as measured by dynamic light scattering (DLSaverage particle diameter): Measured with a dynamic light scatteringparticle diameter analyzer Zetasizer Nano (available from MalvernPanalytical, Spectris Co., Ltd.) after dilution of an aqueous sol.

Zeta potential: An aqueous sol was diluted, and then 0.4 M sulfuric acidwas added thereto, to thereby adjust the pH of the mixture to 2.Thereafter, while 0.25 M aqueous NaOH solution was added to the mixturefor increasing the pH of the mixture, the zeta potential was measured atdifferent pH values with a zeta potential/particle diameter/molecularweight measuring system ELSZ-2000ZS (available from Otsuka ElectronicsCo., Ltd.).

Preparation of rock core sample: A rock core sample was pulverized, andthe compositional data of the rock core sample (in terms of metal oxide)were obtained with a wavelength dispersion-type fluorescent X-rayanalyzer Supermini 200 (available from Rigaku Corporation).

Observation of profile of rock core sample: The surface profile of arock core sample was observed with a scanning electron microscopeJSM-6010LV (available from JEOL Ltd.).

(Salt Composition of Salt Water Used for Evaluation)

Table 1 shows the salt compositions of domestic oil field formationwater (salt concentration: 14,000 ppm), salt water of low saltconcentration (salt concentration: 35,000 ppm), salt water of mediumsalt concentration (salt concentration: 175,000 ppm), and salt water ofhigh salt concentration (salt concentration: 229,000 ppm) used forevaluation.

TABLE 1 Salt Compositions of Salt Waters used for Evaluation Domesticoil field Salt water of low Salt water of medium Salt water of highformation water salt concentration salt concentration salt concentration(14,000 ppm) (35,000 ppm) (175,000 ppm) (229,000 ppm) compositioncomposition composition composition (ppm) (ppm) (ppm) (ppm) NaCl 1200024800 102500 130000 CaCl₂ 200 1100 60000 82500 MgCl₂ 100 5300 1140016700 Na₂SO₄ 200 4100 400 100 H₃BO₃ 1000 — — —

Example 1: Production of Aqueous Sol Containing Silica ParticlesSubjected to Surface Treatment with 3-Glycidoxypropyltrimethoxysilane(GPS)

A 500 mL glass-made eggplant-shaped flask was charged with 300 g of anaqueous silica sol (Snowtex (registered trademark) ST-OXS, availablefrom Nissan Chemical Corporation, silica concentration: 10.5% by mass,average primary particle diameter: 5 nm, pH 3.0) and a stirring bar.Thereafter, while the aqueous silica sol was stirred with a magneticstirrer, 13.5 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade nameKBM-403, available from Shin-Etsu Chemical Co., Ltd.) was added to theflask so that the mass ratio of the silane compound was 0.43 partsrelative to 1.00 part of silica particles contained in the aqueoussilica sol. Subsequently, a cooling tube through which tap water flowedwas provided on the top of the eggplant-shaped flask, and the aqueoussilica sol was heated to 80° C. and maintained under reflux at 80° C.for eight hours. After being cooled to room temperature, the aqueoussilica sol was removed from the flask, to thereby yield 313.5 g of anaqueous silica sol subjected to surface treatment with the silanecompound (GPS) (hereinafter referred to as “aqueous sol of Example 1,”mass ratio of the silane compound relative to 1.00 part of the silicaparticles: 0.43 parts, silica concentration: 11.0% by mass, pH 3.1,viscosity: 1.8 cP, specific gravity: 1.06, DLS average particlediameter: 8.0 nm).

Example 2: Production of Aqueous Sol Containing Silica ParticlesSubjected to Surface Treatment with 3-Aminopropyltriethoxysilane (APTES)and Phenyltrimethoxysilane (PTMS)

A 500 mL glass-made eggplant-shaped flask was charged with 300 g of anaqueous silica sol (Snowtex (registered trademark) ST-OXS, availablefrom Nissan Chemical Corporation, silica concentration: 10.5% by mass,average primary particle diameter: 5 nm, pH 3.0) and a stirring bar.Thereafter, while the aqueous silica sol was stirred with a magneticstirrer, 6.9 g of 85% DL-lactic acid (available from Sigma-Aldrich).Subsequently, 9.5 g of 3-aminopropyltriethoxysilane (APTES) (trade nameKBE-903, available from Shin-Etsu Chemical Co., Ltd.) was added to theflask so that the mass ratio of the silane compound was 0.30 partsrelative to 1.00 part of silica particles contained in the aqueoussilica sol, and the container was sealed and maintained in an oven at60° C. for 12 hours. Subsequently, while the aqueous silica sol wasstirred with the magnetic stirrer, 1.7 g of phenyltrimethoxysilane(PTMS) (trade name KBM-103, available from Shin-Etsu Chemical Co., Ltd.)was added to the flask so that the mass ratio of the silane compound was0.05 parts relative to 1.00 part of the silica particles contained inthe aqueous silica sol. A cooling tube through which tap water flowedwas provided on the top of the eggplant-shaped flask, and the aqueoussilica sol was heated to 60° C. and maintained under reflux at 60° C.for three hours. After being cooled to room temperature, the aqueoussilica sol was removed from the flask, to thereby yield 318.1 g of anaqueous silica sol subjected to surface treatment with the silanecompounds (APTES+PTMS) (hereinafter referred to as “aqueous sol ofExample 2,” mass ratio of the entire silane compound relative to 1.00part of the silica particles: 0.35 parts, silica concentration: 10.8% bymass, pH 4.0, viscosity: 1.8 cP, specific gravity: 1.06, DLS averageparticle diameter: 13.0 nm).

Example 3: Production of Aqueous Sol Containing Silica ParticlesSubjected to Surface Treatment with 3-Glycidoxypropyltrimethoxysilane(GPS) and 2-(3,4-Epoxycyclohexyl)ethyltrimethoxysilane (EPCHS)

A 500 mL glass-made eggplant-shaped flask was charged with 300 g of anaqueous silica sol (Snowtex (registered trademark) ST-OXS, availablefrom Nissan Chemical Corporation, silica concentration: 10.5% by mass,average primary particle diameter: 5 nm, pH 3.0) and a stirring bar.Thereafter, while the aqueous silica sol was stirred with a magneticstirrer, 13.5 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade nameKBM-403, available from Shin-Etsu Chemical Co., Ltd.) was added to theflask so that the mass ratio of the silane compound was 0.43 partsrelative to 1.00 part of silica particles contained in the aqueoussilica sol. Subsequently, a cooling tube through which tap water flowedwas provided on the top of the eggplant-shaped flask, and the aqueoussilica sol was heated to 80° C. and maintained under reflux at 80° C.for eight hours. After cooling of the aqueous silica sol to roomtemperature, while the aqueous silica sol was stirred with the magneticstirrer, 7.0 g of 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS)(trade name KBM-303, available from Shin-Etsu Chemical Co., Ltd.) wasadded to the flask so that the mass ratio of the silane compound was0.22 parts relative to 1.00 part of the silica particles contained inthe aqueous silica sol. Subsequently, a cooling tube through which tapwater flowed was provided on the top of the eggplant-shaped flask, andthe aqueous silica sol was heated to 60° C. and maintained under refluxat 60° C. for three hours. After being cooled to room temperature, theaqueous silica sol was removed from the flask, to thereby yield 320.5 gof an aqueous silica sol subjected to surface treatment with the silanecompounds (GPS+EPCHS) (hereinafter referred to as “aqueous sol ofExample 3,” mass ratio of the entire silane compound relative to 1.00part of the silica particles: 0.65 parts, silica concentration: 11.4% bymass, pH 3.1, viscosity: 2.2 cP, specific gravity: 1.06, DLS averageparticle diameter: 8.9 nm).

Example 4: Production of Aqueous Sol Containing Silica ParticlesSubjected to Surface Treatment with 3-Glycidoxypropyltrimethoxysilane(GPS) and 2-(3,4-Epoxycyclohexyl)ethyltrimethoxysilane (EPCHS)

A 500 mL glass-made eggplant-shaped flask was charged with 300 g of anaqueous silica sol (Snowtex (registered trademark) ST-OS, available fromNissan Chemical Corporation, silica concentration: 20.5% by mass,average primary particle diameter: 9 nm, pH 3.0) and a stirring bar.Thereafter, while the aqueous silica sol was stirred with a magneticstirrer, 14.6 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade nameKBM-403, available from Shin-Etsu Chemical Co., Ltd.) was added to theflask so that the mass ratio of the silane compound was 0.24 partsrelative to 1.00 part of silica particles contained in the aqueoussilica sol. Subsequently, a cooling tube through which tap water flowedwas provided on the top of the eggplant-shaped flask, and the aqueoussilica sol was heated to 80° C. and maintained under reflux at 80° C.for eight hours. After cooling of the aqueous silica sol to roomtemperature, while the aqueous silica sol was stirred with the magneticstirrer, 15.2 g of 2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane (EPCHS)(trade name KBM-303, available from Shin-Etsu Chemical Co., Ltd.) wasadded to the flask so that the mass ratio of the silane compound was0.25 parts relative to 1.00 part of the silica particles contained inthe aqueous silica sol. Subsequently, a cooling tube through which tapwater flowed was provided on the top of the eggplant-shaped flask, andthe aqueous silica sol was heated to 60° C. and maintained under refluxat 60° C. for three hours. After being cooled to room temperature, theaqueous silica sol was removed from the flask, to thereby yield 329.8 gof an aqueous silica sol subjected to surface treatment with the silanecompounds (GPS+EPCHS) (hereinafter referred to as “aqueous sol ofExample 4,” mass ratio of the entire silane compound relative to 1.00part of the silica particles: 0.49 parts, silica concentration: 20.8% bymass, pH 2.9, viscosity: 3.3 cP, specific gravity: 1.13, DLS averageparticle diameter: 18.2 nm).

Comparative Example 1: Production of Aqueous Sol Containing SilicaParticles Subjected to Surface Treatment with3-Glycidoxypropyltriethoxysilane (GPTES)

Water was added to commercially available sodium water glass (JIS No. 3sodium water glass, SiO₂ concentration: 28.8% by mass, Na₂Oconcentration: 9.5% by mass) to thereby prepare an aqueous sodiumsilicate solution having a silica concentration of 3.8% by mass. Theaqueous sodium silicate solution was caused to pass through a columncharged with a hydrogen type strongly acidic cation exchange resin(Amberlite IR-120B, available from The Dow Chemical Company), to therebyprepare a colloidal aqueous solution of active silica (silicaconcentration: 3.6% by mass, pH 3.2).

A reaction device including a glass-made reaction container (innervolume: 3 L) equipped with a stirrer, a heater, etc. was charged with11.9 g of 10% aqueous sodium hydroxide solution and 291.7 g of purewater, and the mixture was heated to 55° C. Thereafter, while themixture was maintained at 55° C., 732.0 g of the colloidal aqueoussolution of active silica was continuously added to the mixture over twohours. Subsequently, while the temperature of the mixture was increasedto 80° C., 1,464.4 g of the colloidal aqueous solution of active silicawas continuously added to the mixture over four hours. The resultantmixture was then maintained at 80° C. for six hours to thereby yield2,500.0 g of a dilute alkaline silica sol (silica concentration: 3.1% bymass, pH 9.7, average primary particle diameter: 7 nm). Subsequently,the dilute alkaline silica sol was concentrated with an ultrafiltrationdevice to thereby prepare an alkaline aqueous silica sol (silicaconcentration: 28% by mass, average primary particle diameter: 7 nm, pH9.0, viscosity: 5 cP, specific gravity: 1.2, DLS average particlediameter: 9.4 nm).

A 500 mL glass-made eggplant-shaped flask was charged with 250 g of thealkaline aqueous silica sol and a stirring bar. Thereafter, while theaqueous silica sol was stirred with a magnetic stirrer, an aqueous HClsolution was added to adjust the pH to 8, and 18.9 g of3-glycidoxypropyltriethoxysilane (GPTES) (trade name KBE-403, availablefrom Shin-Etsu Chemical Co., Ltd.) was added to the flask so that themass ratio of the silane compound was 0.27 parts relative to 1.00 partof silica particles contained in the aqueous silica sol. Thereafter, theresultant mixture was maintained at 23° C. for two hours. The aqueoussilica sol was removed from the flask, to thereby yield 269.0 g of anaqueous silica sol subjected to surface treatment with the silanecompound (GPTES) (hereinafter referred to as “aqueous sol of ComparativeExample 1,” mass ratio of the silane compound relative to 1.00 part ofthe silica particles: 0.27 parts, silica solid content: 28% by mass,average primary particle diameter: 7 nm, pH 8, viscosity: 5 cP, specificgravity: 1.2, DLS average particle diameter: 19.0 nm).

Comparative Example 2: Production of Aqueous Sol Containing SilicaParticles Subjected to Surface Treatment with3-Glycidoxypropyltrimethoxysilane (GPS)

A 500 mL glass-made eggplant-shaped flask was charged with 300 g of anaqueous silica sol (Snowtex (registered trademark) ST-XS, available fromNissan Chemical Corporation, silica concentration: 20.5% by mass,average primary particle diameter: 5 nm, pH 9.5) and a stirring bar.Thereafter, while the aqueous silica sol was stirred with a magneticstirrer, 26.3 g of 3-glycidoxypropyltrimethoxysilane (GPS) (trade nameKBM-403, available from Shin-Etsu Chemical Co., Ltd.) was added to theflask so that the mass ratio of the silane compound was 0.43 partsrelative to 1.00 part of silica particles contained in the aqueoussilica sol. Subsequently, the resultant mixture was maintained at 23° C.for two hours. The aqueous silica sol subjected to surface treatmentwith the silane compound (GPS) aggregated and became whitely turbidduring a production process, resulting in failure to produce ahomogeneous aqueous sol.

[Results of Measurement of Zeta Potential]

FIG. 1 shows the results of measurement of the zeta potentials of theaqueous sols (aqueous silica sols subjected to surface treatment with asilane compound) prepared in Examples 1 and 2 at different pH valuesfrom pH 2 or more to pH 10 or less.

As shown in FIG. 1 , the aqueous sol of Example 1 exhibited a negativezeta potential at a pH of 6 or less, and the aqueous sol of Example 2exhibited a positive zeta potential at a pH of 6 or less; i.e., boththese aqueous sols did not have an isoelectric point at a pH of 6 orless.

[Test for Stability Against Salt Water]

The aqueous sols of Example 1 and Comparative Example 1 were subjectedto a test for stability against salt water (salt water stability test).

The aqueous sol of Example 1 (silica sol containing silica particlessubjected to surface treatment with 3-glycidoxypropyltrimethoxysilane(GPS), silane compound:silica particles=0.43:1 (mass ratio), pH 3.1, DLSaverage particle diameter: 8.0 nm) or the aqueous sol of ComparativeExample 1 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltriethoxysilane (GPTES), silanecompound:silica particles=0.27:1 (mass ratio), pH 8, DLS averageparticle diameter: 19.0 nm) was added to salt water so as to achieve asilica concentration of 1.0% by mass. In this case, samples for the saltwater stability test were prepared so as to achieve a low saltconcentration (salt concentration: 35,000 ppm), a medium saltconcentration (salt concentration: 175,000 ppm), or a high saltconcentration (salt concentration: 229,000 ppm).

An aqueous NaOH solution was added to the sample of Example 1, and anaqueous HCl solution was added to the sample of Comparative Example 1,to thereby prepare aqueous sols having any pH values. The resultantaqueous sols were used for the salt water stability test.

Each of the above-prepared samples was stored at a temperature of 80°C., and the sample was evaluated for a change in average particlediameter as measured by dynamic light scattering (DLS average particlediameter: nm).

The results are shown in FIG. 2 and Table 2 (low salt concentration:35,000 ppm), FIG. 3 and Table 3 (medium salt concentration: 175,000ppm), and FIG. 4 and Table 4 (high salt concentration: 229,000 ppm).

In Table 2, “Example 1, pH 3” in the column “Aqueous sol” corresponds toa sample prepared by storing the aqueous sol of Example 1 after pHadjustment to 3, and then diluting the aqueous sol with salt water oflow salt concentration (35,000 ppm) so as to achieve a silicaconcentration of 1.0% by mass. The sample diluted with salt water (pH6.4) was evaluated for a change in DLS average particle diameter duringstorage at 80° C.

In Table 2, “Example 1, pH 5” in the column “Aqueous sol” corresponds toa sample prepared by storing the aqueous sol of Example 1 after pHadjustment to 5, and then diluting the aqueous sol with salt water oflow salt concentration (35,000 ppm) so as to achieve a silicaconcentration of 1.0% by mass. The sample diluted with salt water (pH6.5) was evaluated for a change in DLS average particle diameter duringstorage at 80° C.

In Table 2, “Example 1, pH 6” in the column “Aqueous sol” corresponds toa sample prepared by storing the aqueous sol of Example 1 after pHadjustment to 6, and then diluting the aqueous sol with salt water oflow salt concentration (35,000 ppm) so as to achieve a silicaconcentration of 1.0% by mass. The sample diluted with salt water (pH6.7) was evaluated for a change in DLS average particle diameter duringstorage at 80° C.

In Table 2, “Example 1, pH 9” in the column “Aqueous sol” corresponds toa sample prepared by storing the aqueous sol of Example 1 after pHadjustment to 9, and then diluting the aqueous sol with salt water oflow salt concentration (35,000 ppm) so as to achieve a silicaconcentration of 1.0% by mass. The sample diluted with salt water (pH7.0) was evaluated for a change in DLS average particle diameter duringstorage at 80° C.

In Table 2, “Comparative Example 1, pH 8” in the column “Aqueous sol”corresponds to a sample prepared by storing the aqueous sol ofComparative Example 1 after pH adjustment to 8, and then diluting theaqueous sol with salt water of low salt concentration (35,000 ppm) so asto achieve a silica concentration of 1.0% by mass. The sample dilutedwith salt water (pH 6.9) was evaluated for a change in DLS averageparticle diameter during storage at 80° C.

In Table 2, “Comparative Example 1, pH 3” in the column “Aqueous sol”corresponds to a sample prepared by storing the aqueous sol ofComparative Example 1 after pH adjustment to 3, and then diluting theaqueous sol with salt water of low salt concentration (35,000 ppm) so asto achieve a silica concentration of 1.0% by mass. The sample dilutedwith salt water (pH 6.4) was evaluated for a change in DLS averageparticle diameter during storage at 80° C.

Similarly, samples shown in Tables 3 and 4 were prepared by storing theaqueous sols of Example 1 and Comparative Example 1 after pH adjustmentto different values (see pH in the column “Aqueous sol”), and dilutingthe aqueous sols with salt water of medium salt concentration or highsalt concentration so as to achieve a silica concentration of 1.0% bymass and a pH of 5.0 or more to 8.0 or less (see the column “pH of saltwater stability test sample”). Each of the samples diluted with saltwater was evaluated for a change in DLS average particle diameter duringstorage at 80° C. for 30 days.

As shown in FIG. 2 and Table 2 (low salt concentration), FIG. 3 andTable 3 (medium salt concentration), and FIG. 4 and Table 4 (high saltconcentration), the aqueous sol of Example 1 (pH of 3 or more to 6 orless) exhibited a small change in DLS average particle diameter evenafter storage at 80° C. for 30 days, as compared with the aqueous sol ofComparative Example 1. However, the aqueous sol of Example 1 (pH of 9)in the case of low salt concentration and medium salt concentration, orthe aqueous sol of Example 1 (pH of 7 or more) in the case of high saltconcentration exhibited a large change in average particle diameter;specifically, a change in DLS average particle diameter of more than 200nm between before and after storage for 30 days.

TABLE 2 DLS Value, Low Salt Concentration (35,000 ppm) pH of salt waterstability DLS average particle Change test sample diameter (nm) in DLS(silica Immediately After storage particle concentration: after at 80°C. diameter Aqueous sol 1.0% by mass) preparation for 30 days (nm)Example 1 6.4 26.5 28.3 1.8 pH 3 Example 1 6.5 26.8 39.1 12.3 pH 5Example 1 6.7 26.2 45.2 19.0 pH 6 Example 1 7.0 27.1 277.6 250.5 pH 9Comparative 6.9 27.0 Unmeasurable — Example 1 pH 8 Comparative 6.4 26.0Unmeasurable — Example 1 pH 3

TABLE 3 DLS Value, Medium Salt Concentration (175,000 ppm) pH of saltwater stability DLS average particle Change test sample diameter (nm) inDLS (silica Immediately After storage particle concentration: after at80° C. diameter Aqueous sol 1.0% by mass) preparation for 30 days (nm)Example 1 6.3 28.0 40.5 12.5 pH 3 Example 1 6.6 26.1 32.4 6.3 pH 5Example 1 6.7 26.0 37.0 11.0 pH 6 Example 1 7.3 26.3 283.0 256.7 pH 9Comparative 7.2 27.1 Unmeasurable — Example 1 pH 8 Comparative 6.3 27.0Unmeasurable — Example 1 pH 3

TABLE 4 DLS Value, High Salt Concentration (229,000 ppm) pH of saltwater stability DLS average particle Change test sample diameter (nm) inDLS (silica Immediately After storage particle concentration: after at80° C. diameter Aqueous sol 1.0% by mass) preparation for 30 days (nm)Example 1 5.3 27.2 129.5 102.3 pH 3 Example 1 5.8 26.0 150.0 124.0 pH 5Example 1 6.0 27.1 182.6 155.5 pH 6 Example 1 6.4 30.0 258.0 228.0 pH 7Example 1 6.9 30.1 428.0 397.9 pH 9 Comparative 6.4 35.0 Unmeasurable —Example 1 pH 8 Comparative 5.4 33.0 Unmeasurable — Example 1 pH 3

[Foamability Test]

The aqueous sols of Examples 1, 2, 3, and 4 and Comparative Example 1were subjected to a foamability test using an apparatus shown in FIG. 5through the following procedure.

Salt water containing each of the aqueous silica sols subjected tosurface treatment (the aqueous sols of Examples 1 to 4 and ComparativeExample 1) (silica concentration: 1.0% by mass) was placed in apressure-resistant cell for visual observation having an observationwindow (available from TAMASEIKI IND. Co., Ltd., volume: 150 mL).Thereafter, the pressure-resistant cell was heated to a temperature of100° C., and carbon dioxide (available from Nippon Ekitan Corporation,purity: 99.99% or more) was injected into the cell until the internalpressure reached 100 atm, 200 atm, or 300 atm. The aqueous silica solwas stirred with a stirring bar at a rotation speed of 1,000 to 1,500rpm for 15 minutes, and then the stirring was terminated to therebyallow the sol to stand still. The foamability was evaluated by visualobservation of the state of formation of froth or emulsion through theobservation window.

<Foamability Test 1>

The aqueous sols of Examples 1 and 2 and Comparative Example 1 weresubjected to a foamability test using a crude oil substitute (n-decane).

The aqueous sol of Example 1 (silica sol containing silica particlessubjected to surface treatment with 3-glycidoxypropyltrimethoxysilane(GPS), silane compound:silica particles=0.43:1 (mass ratio)), theaqueous sol of Example 2 (silica sol containing silica particlessubjected to surface treatment with 3-aminopropyltriethoxysilane (APTES)and phenyltrimethoxysilane (PTMS), silane compound:silicaparticles=0.35:1 (mass ratio)), or the aqueous sol of ComparativeExample 1 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltriethoxysilane (GPTES), silanecompound:silica particles=0.27:1 (mass ratio)) was added to salt waterso as to achieve a silica concentration of 1.0% by mass, to therebyprepare three salt water samples (salt concentration: 229,000 ppm (saltwater of high salt concentration)) for foamability test 1.

Each salt water sample for foamability test 1 was mixed with carbondioxide so as to achieve (a) the salt water sample:carbon dioxide=50:50(proportions by volume) or mixed with carbon dioxide and decane so as toachieve (b) the salt water sample:carbon dioxide:decane=20:60:20(proportions by volume), and the resultant mixture was stirred at atemperature of 100° C. and a pressure of 100 atm, 200 atm, or 300 atmwith a stirring bar at a rotation speed of 1,500 rpm for 15 minutes.

FIG. 6 shows observation photographs of the mixture samples immediatelyafter termination of the stirring (0 min) and after being allowed tostand still for 30 minutes.

In the observation photographs shown in FIG. 6 and FIGS. 7 and 8 below,the cloudy portion (uniform white portion) in each circle (observationwindow) indicates the formation of froth or emulsion, and the darkportion on the lower side of the circle indicates salt water. Theobservation of voids or color unevenness in the cloudy portion of thecircle indicates insufficient formation of froth or emulsion. Theformation of froth or emulsion enables it to enter pores in the rockcore and function in recovering crude oil.

As shown in FIG. 6(a), the sample prepared by mixing the salt watersample for foamability test 1 (“SALT WATER” shown in FIG. 6 ) and carbondioxide in proportions by volume of 50/50 using each of the aqueous solsof Examples 1 and 2 exhibited high foamability.

As shown in FIG. 6(b), the sample prepared by mixing the salt watersample for foamability test 1, carbon dioxide, and the crude oilsubstitute (n-decane) in proportions by volume of 20/60/20 using each ofthe aqueous sols of Examples 1 and 2 exhibited high foamability.

These results suggest that the aqueous sols of Examples 1 and 2 havehigh ability to sweep crude oil in pores of the core sample.

In contrast, in the case of the Comparative Example, voids or colorunevenness was observed on the upper side of the circle immediatelyafter termination of the 15-minute stirring (0 min) and even after beingallowed to stand still for 30 minutes (i.e., insufficient formation offroth or emulsion), particularly as shown in the results of the testusing the crude oil substitute (FIG. 6(b)). The results suggest that theaqueous sol of the Comparative Example have poor ability to sweep crudeoil.

<Foamability Test 2>

The aqueous sols of Examples 3 and 4 and Comparative Example 1 weresubjected to a foamability test.

The aqueous sol of Example 3 (silica sol containing silica particlessubjected to surface treatment with 3-glycidoxypropyltrimethoxysilane(GPS) and epoxycyclohexylethyltrimethoxysilane (EPCHS), silanecompound:silica particles=0.65:1 (mass ratio)), the aqueous sol ofExample 4 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltrimethoxysilane (GPS) andepoxycyclohexylethyltrimethoxysilane (EPCHS), silane compound:silicaparticles=0.49:1 (mass ratio)), or the aqueous sol of ComparativeExample 1 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltriethoxysilane (GPTES), silanecompound:silica particles=0.27:1 (mass ratio)) was added to salt waterso as to achieve a silica concentration of 1.0% by mass, to therebyprepare three salt water samples (salt concentration: 14,000 ppm(domestic oil field formation water)) for foamability test 2.

Each salt water sample for foamability test 2 was mixed with carbondioxide so as to achieve the salt water sample:carbon dioxide=50:50(proportions by volume), and the resultant mixture was stirred at atemperature of 100° C. and a pressure of 185 atm or 300 atm with astirring bar at a rotation speed of 1,000 rpm, 1,250 rpm, or 1,500 rpmfor 15 minutes.

FIG. 7 shows observation photographs of the mixture samples immediatelyafter termination of the stirring and after being allowed to stand stillfor 30 minutes following the 15-minute stirring at 1,500 rpm.

As shown in FIG. 7 , the sample prepared by using each of the aqueoussols of Examples 3 and 4 exhibited high foamability. The results suggestthat the aqueous sols of Examples 3 and 4 have high ability to sweepcrude oil in pores of the rock core.

<Foamability Test 3: Long-Term Stability Test of Froth or Emulsion>

The aqueous sol of Example 1 (silica sol containing silica particlessubjected to surface treatment with 3-glycidoxypropyltrimethoxysilane(GPS), silane compound:silica particles=0.43:1 (mass ratio)) or theaqueous sol of Example 2 (silica sol containing silica particlessubjected to surface treatment with 3-aminopropyltriethoxysilane (APTES)and phenyltrimethoxysilane (PTMS), silane compound:silicaparticles=0.35:1 (mass ratio)) was added to salt water so as to achievea silica concentration of 1.0% by mass, to thereby prepare two saltwater samples (salt concentration: 229,000 ppm (salt water of high saltconcentration)) for foamability test 3.

Each salt water sample for foamability test 3 was mixed with carbondioxide and decane so as to achieve the salt water sample:carbondioxide:decane=20:60:20 (proportions by volume), and the resultantmixture was stirred at a temperature of 100° C. and a pressure of 200atm with a stirring bar at a rotation speed of 1,500 rpm for 15 minutes.

FIG. 8 shows observation photographs of the mixture samples after beingallowed to stand still for 30 minutes, one day, three days, and sevendays following termination of the stirring.

As shown in FIG. 8 , the sample prepared by using each of the aqueoussols of Examples 1 and 2 maintained high foamability even after beingallowed to stand still for seven days. The results indicate that theformed froth or emulsion exhibits excellent long-term stability.

<Observation of Froth or Emulsion>

The aqueous sol of Example 1 (silica sol containing silica particlessubjected to surface treatment with 3-glycidoxypropyltrimethoxysilane(GPS), silane compound:silica particles=0.43:1 (mass ratio)) was addedto salt water so as to achieve a silica concentration of 1.0% by mass,to thereby prepare a salt water sample (salt concentration: 229,000 ppm(salt water of high salt concentration), pH 5.2) for observation offroth or emulsion.

A water-soluble dye (methyl orange) of the following Formula (1) wasadded to the salt water sample for observation of froth or emulsion sothat the dye content of the salt water was 0.3% by mass.

The salt water sample for observation of froth or emulsion was mixedwith carbon dioxide and decane so as to achieve the salt watersample:carbon dioxide:decane=50:30:20 (proportions by volume), and theresultant mixture was stirred at a temperature of 100° C. and a pressureof 100 atm to 300 atm with a stirring bar at a rotation speed of 1,500rpm for 15 minutes.

The stirred sample was transferred from the pressure-resistant cell forvisual observation of the apparatus used for the foamability test shownin FIG. 5 to a pressure-resistant cell for microscopic observation, andthe state of froth or emulsion was observed with an optical microscope.

FIGS. 9 and 10 are optical microscope photographs showing emulsion eachformed at a pressure of 100 atm, and FIG. 11 is an optical microscopephotograph showing froth formed at a pressure of 300 atm.

FIGS. 12 and 13 are schematic views each showing the formation of theemulsion, and FIG. 14 is a schematic view showing the formation of thefroth.

FIG. 9 (see the schematic view of FIG. 12 ) shows W/O emulsioncontaining a continuous phase formed of decane, and a dispersed phaseformed by coexistence of colorless droplets (carbon dioxide) and darkdroplets (water containing silica particles). As shown in FIG. 12 , eachdark droplet (dispersed phase formed of water containing silicaparticles) is formed of silica particles on the surface of the droplet,internal water, and silica particles in the water.

FIG. 10 (see the schematic view of FIG. 13 ) shows O/W emulsioncontaining a continuous phase formed of water containing silicaparticles, and a dispersed phase formed by coexistence of droplets(carbon dioxide) and droplets (decane). As shown in FIG. 13 , thecontinuous phase is formed of water and silica particles in the water,and the dispersed phase is formed of carbon dioxide or decane (droplets)wherein silica particles are present on the surface of each droplet.

FIG. 11 (see the schematic view of FIG. 14 ) shows a dispersed phasecontaining froth formed of a homogeneous phase containing decane andcarbon dioxide and silica particles present on the surface of the froth,and a continuous phase formed of water containing silica particles.

[Composition and Profile Observation of Rock Core Sample]

The compositional data of a rock core sample used for evaluation ofcrude oil recovery described below were obtained through theaforementioned procedure, and the profile of the rock core sample wasobserved.

The rock core sample used was a sandstone sample (SiO₂ type) of BereaSandstone (available from Core Lab Instruments, hereinafter referred toas “BSS”) or a carbonate rock sample (CaCO₃ type) of Indiana 200md(available from Kocurek, hereinafter referred to as “IN 200md”).

The rock core sample (sandstone sample or carbonate rock sample) usedfor various evaluation tests was a cylindrical sample having a diameterof 1.5 inches and a length of 1 foot (about 3.8 cm in diameter×30.5 cmin length) prepared by reflux-extraction washing with toluene forremoval of oil and water followed by one-day drying at 120° C., and thenreflux-extraction washing with methanol for removal of salt followed byone-day drying at 80° C.

Table 5 shows the resultant compositional data of each sample(fluorescent X-ray analysis, composition in terms of oxide). FIG. 15 isa photograph showing the appearances of rock core samples, as well asthe results of observation of the surface profiles of the samples(scanning electron microscope photographs (magnification: 500)) (FIG.15(a): sandstone (BSS), FIG. 15(b): carbonate rocks (IN 200md)).

TABLE 5 Rock Core Sample (Composition in terms of oxides) SandstoneCarbonate rocks Component (SiO₂ type) (CaCO₃ type) (% by mass) BSS IN200 md SiO₂ 88.5 0.6 Al₂O₃ 6.6 — CaO 1.1 98.0 MgO 0.5 0.4 Fe₂O₃ 1.9 0.8K₂O 1.4 0.2

[Pore Volume and Air Permeability of Rock Core Sample]

The porosity and air permeability of the aforementioned rock core samplewere measured to thereby determine the pore volume thereof.

The porosity was measured with a helium porosimeter (available from CoreLab Instruments).

The air permeability was measured with an air permeameter (availablefrom Core Lab Instruments).

These measurements were performed on five samples of sandstone (BSS) andnine samples of carbonate rocks (IN 200md). The results are shown inTables 6 and 7.

TABLE 6 Pore Volume and Air Permeability of Sandstone Sample Pore Airvolume Porosity permeability Sandstone sample (cc) (%) (md) BereaSandstone-1 64.8 19.3 252 Berea Sandstone-2 64.3 19.0 251 BereaSandstone-3 64.4 19.1 255 Berea Sandstone-4 64.5 19.0 252 BereaSandstone-5 64.5 19.0 251

TABLE 7 Pore Volume and Air Permeability of Carbonate Rock Sample PoreAir volume Porosity permeability Carbonate rock sample (cc) (%) (md)Indiana 200md-l 53.5 15.5 217 Indiana 200md-2 51.6 15.0 107 Indiana200md-3 51.9 15.1 177 Indiana 200md-4 48.3 14.0 111 Indiana 200md-5 44.913.0 64 Indiana 200md-6 50.5 14.6 253 Indiana 200md-7 49.3 14.3 76Indiana 200md-8 52.4 15.2 320 Indiana 200md-9 49.9 14.5 160

The carbonate rock samples (IN 200md) used for crude oil recoverevaluation described below were selected as follows. Specifically, onthe basis of the K (air permeability)-Phi (porosity) plot shown in FIG.16 , core samples of low permeability (□) and core samples of highpermeability (Δ) were eliminated, and rock core samples of mediumpermeability (air permeability: about 150±50 md) (●) were selected andused for evaluation of crude oil recovery.

[Evaluation of Crude Oil Recovery Using Rock Core Sample]

The aqueous sol prepared in Example 1 was evaluated for crude oilrecovery (assuming subsurface oil reservoir) through the proceduredescribed below by using the core flow test apparatus (pipe andequipment layout) shown in FIG. 17 and using Middle East crude oil androck core samples (sandstone (BSS) and carbonate rocks (IN 200md)).

As shown in FIG. 17 , the core flow test apparatus includes injectionpumps (available from Schlumberger), a CO₂ piston cylinder for fluidcharging, a piston cylinder for nanoparticles and salt water, and acrude oil piston cylinder (available from VINCI Technologies), a coreholder (available from VINCI Technologies), a confining pressure pump(available from VINDUM ENGINEERING), a back pressure valve and a backpressure pump (available from VINCI Technologies), a gas-liquidseparator (crude oil recovery unit) for a recovered fluid (availablefrom VINCI Technologies), a wet gas meter for measuring the amount offree gas (available from Shinagawa Corporation), a pressure transducer(available from VALCOM), a resistance thermometer bulb for measuring acore temperature, a thermostatic chamber temperature, and a free gastemperature (available from Chino Corporation), and an air thermostaticchamber (available from Sunaka Rika Kogyo K. K.). The upstream anddownstream pressures of the core holder, the confining pressure (lateralpressure) of the core holder, the pressure for control of the backpressure valve, the temperatures of the core and the thermostaticchamber, and the amount and temperature of the free gas were recordedevery second by a computer via a data logger (available from GRAPHTEC).

Test Example 1: Evaluation of Crude Oil Recovery Using Sandstone (BSS)

A sandstone (BSS) core sample (one sample) inserted in a rubber sleevewas placed in the core holder shown in FIG. 17 , and the pores of thesandstone (BSS) core were vacuumed, followed by vacuuming of the annularspace between the rubber sleeve and the inner wall of the core holder(annular space for fluid charging by confining pressure (lateralpressure)). After the annular space was saturated with a pressurizedfluid from the confining pressure pump by atmospheric pressure suction,the confining pressure (lateral pressure) was increased to 68.0 atm withthe confining pressure pump, to thereby determine no leakage into thepores of the sandstone (BSS) core and to the exterior. The back pressurevalve was set to 200 atm (i.e., test conditions) with the back pressurepump. The injection pump 2 was connected to the crude oil pistoncylinder, and the crude oil was introduced into the vacuumed pores ofthe sandstone (BSS) core, followed by pressurization to 34.0 atm andcontrol of the pump at constant pressure. In order to achieve thedifferential pressure set for the crude oil recovery evaluation test(back-pressure setting pressure+68.0 atm (1,000 psi)), the confiningpressure (lateral pressure) was increased to 102.0 atm, and the amountof the introduced crude oil was recorded. The preliminarily measureddead volume between the upstream and downstream valves of the coreholder was subtracted from the amount of the introduced crude oil at adifferential pressure of 68.0 atm, to thereby determine the 100% crudeoil saturation volume of the core pores, which was used as the core porevolume for calculation of the crude oil recovery rate. While checkingthat there is no leakage, the confining pressure (lateral pressure) andthen the pressure in the core pores were increased in increments of 34.0atm, and the confining pressure (lateral pressure) and the pressure inthe core pores were set to 268.1 atm and 200.0 atm (test pressures),respectively. The injection pump 2 was set to constant flow ratecontrol, and the crude oil was injected at a low flow rate, to therebydetermine the operation of the back pressure valve and the signal outputstatus of the pressure transducer. The upstream valve of the crude oilpiston cylinder was closed, and the internal pressure of the pistoncylinder for fluid charging was controlled at a constant pressure of 200atm by the injection pumps 1 and 2. The air thermostatic chamber washeated from room temperature in increments of 10° C., and thetemperature of the air thermostatic chamber was maintained at 100° C.(test temperature). Regarding the fluid expansion volume during anincrease in temperature, the internal pressure of the piston cylinderfor fluid charging was maintained at 200 atm by the injection pumps 1and 2, the crude oil in the core holder was discharged from the backpressure valve and maintained at 200 atm, and the confining pressure(lateral pressure) was maintained at 268.1 atm by the confining pressurepump.

Subsequently, the liquid prepared with salt water (silica concentration:1.0% by mass, salt concentration: 175,000 ppm (salt water of medium saltconcentration)) containing the aqueous sol of Example 1 (silica solcontaining silica particles subjected to surface treatment with3-glycidoxypropyltrimethoxysilane (GPS)) was injected from the pistoncylinder for nanoparticles and salt water, and carbon dioxide wasinjected from the CO₂ piston cylinder. The salt water-prepared liquidand carbon dioxide were simultaneously injected at a ratio of 1:1 at aflow rate of 4 feet/day into the sandstone (BSS) core sample saturatedwith the crude oil in the core holder. For Comparative Test Example,only carbon dioxide was injected at a flow rate of 4 feet/day into thecore sample saturated with the crude oil. The injection fluid wasinjected into the core sample at 100° C., a back-pressure controlpressure of 200 atm, and a confining pressure (lateral pressure) of268.1 atm. The injection was performed until the volume of the injectionfluid reacted 120% relative to the pore volume of the core sample.

The crude oil recovery rate was calculated from the amount of the crudeoil recovered from the pores of the sandstone (BSS) core sample by theinjection of the injection fluid (the aqueous sol of Example 1, the saltwater, and carbon dioxide) into the core sample. The results are shownin FIG. 18 and Table 8.

Also, the liquid prepared with salt water (silica concentration: 1.0% bymass, salt concentration: 175,000 ppm (salt water of medium saltconcentration)) containing the aqueous sol of Example 2 (silica solcontaining silica particles subjected to surface treatment with3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS))was used, and the crude oil recovery rate was evaluated through the sameprocedure as described above. The results are also shown in FIG. 18 andTable 8.

FIG. 18 and Table 8 show the amount of injection (the volume ratio ofthe injected fluid to the pores (injection volume/pore volume):PV) ofthe fluid (the aqueous sol of Example 1 or Example 2, the salt water,and carbon dioxide) (corresponding to the horizontal axis), and theamount (%) of the crude oil recovered from the pores of the sandstone(BSS) core sample (corresponding to the vertical axis) when the totalrock pore volume of the core sample is taken as 1.0. In FIG. 18 , thesymbol “●” corresponds to the results of simultaneous injection of thesalt water (silica concentration: 1.0% by mass, salt concentration:175,000 ppm) containing the aqueous sol of Example 1 (silica solcontaining silica particles subjected to surface treatment with3-glycidoxypropyltrimethoxysilane (GPS)) and carbon dioxide at a ratioof 1:1 at a flow rate of 4 feet/day; the symbol “⋄” corresponds to theresults of simultaneous injection of the salt water (silicaconcentration: 1.0% by mass, salt concentration: 175,000 ppm) containingthe aqueous sol of Example 2 (silica sol containing silica particlessubjected to surface treatment with 3-aminopropyltriethoxysilane (APTES)and phenyltrimethoxysilane (PTMS)) and carbon dioxide at a ratio of 1:1at a flow rate of 4 feet/day; and the symbol “◯” corresponds to theresults of injection of only carbon dioxide at a flow rate of 4feet/day.

As shown in FIG. 18 and Table 8, when the amount of injection of thefluid into the pores of the sandstone (BSS) core sample reached 1.20(120%), the crude oil recovery rate was 58.5% in the case of injectionof the aqueous sol of Example 1, the salt water, and carbon dioxide; thecrude oil recovery rate was 61.6% in the case of injection of theaqueous sol of Example 2, the salt water, and carbon dioxide; and thecrude oil recovery rate was 50.5% in the case of injection of onlycarbon dioxide.

TABLE 8 Sandstone (BSS) Core Sample, Crude Oil Recovery Rate Example 1Example 2 CO₂ foam CO₂ foam Comparative Example Crude oil Crude oilVolume ratio CO₂ Volume ratio recovery rate Volume ratio recovery rateof injected Crude oil of injected (%) of injected (%) fluid to pores:recovery rate fluid to pores: Example 1 fluid to pores: Example 2 PV (%)PV (GPS type) PV (APTES type) 0.00 0.0 0.00 0.0 0.00 0.0 0.16 10.1 0.108.6 0.08 9.8 0.26 15.2 0.21 16.8 0.21 23.9 0.35 19.6 0.33 24.4 0.34 35.60.44 25.5 0.45 32.0 0.47 43.3 0.54 29.2 0.57 39.2 0.60 49.2 0.63 32.70.69 47.7 0.73 55.0 0.72 36.5 0.80 54.2 0.86 57.3 0.82 39.4 0.92 56.30.99 59.2 0.91 42.5 1.04 57.2 1.12 60.6 1.09 48.1 1.16 58.1 1.20 61.61.20 50.5 1.20 58.5 — —

Test Example 2: Crude Oil Recovery Test Using Carbonate Rocks (IN 200md)

A carbonate rock (IN 200md) core sample (one sample) inserted in arubber sleeve was placed in the core holder shown in FIG. 17 , and thepores of the carbonate rock (IN 200md) core were vacuumed, followed byvacuuming of the annular space between the rubber sleeve and the innerwall of the core holder (annular space for fluid charging by confiningpressure (lateral pressure)). Afterwards, the annular space wassaturated with a pressurized fluid from the confining pressure pump byatmospheric pressure suction, the confining pressure (lateral pressure)was increased to 68.0 atm with the confining pressure pump, to therebydetermine that there was no leakage into the pores of the carbonate rock(IN 200md) core and to the exterior. The back pressure valve was set to200 atm (i.e., test conditions) with the back pressure pump. Theinjection pump 2 was connected to the crude oil piston cylinder, and thecrude oil was introduced into the vacuumed pores of the carbonate rock(IN 200md) core, followed by pressurization to 34.0 atm and control ofthe pump at constant pressure. In order to achieve the differentialpressure set for the crude oil recovery evaluation test (back-pressuresetting pressure+68.0 atm (1,000 psi)), the confining pressure (lateralpressure) was increased to 102.0 atm, and the amount of the introducedcrude oil was recorded. The preliminarily measured dead volume betweenthe upstream and downstream valves of the core holder was subtractedfrom the amount of the introduced crude oil at a differential pressureof 68.0 atm, to thereby determine the 100% crude oil saturation volumeof the core pores, which was used as the core pore volume forcalculation of the crude oil recovery rate. While determining that therewas no leakage, the confining pressure (lateral pressure) and then thepressure in the core pores were increased in increments of 34.0 atm, andthe confining pressure (lateral pressure) and the pressure in the corepores were set to 268.1 atm and 200.0 atm (test pressures),respectively. The injection pump 2 was set to constant flow ratecontrol, and the crude oil was injected at a low flow rate, to therebydetermine the operation of the back pressure valve and the signal outputstatus of the pressure transducer. The upstream valve of the crude oilpiston cylinder was closed, and the internal pressure of the pistoncylinder for fluid charging was controlled at a constant pressure of 200atm by the injection pumps 1 and 2. The air thermostatic chamber washeated from room temperature in increments of 10° C., and thetemperature of the air thermostatic chamber was maintained at 100° C.(test temperature). Regarding the fluid expansion volume during anincrease in temperature, the internal pressure of the piston cylinderfor fluid charging was maintained at 200 atm by the injection pumps 1and 2, the crude oil in the core holder was discharged from the backpressure valve and maintained at 200 atm, and the confining pressure(lateral pressure) was maintained at 268.1 atm by the confining pressurepump.

Subsequently, the liquid prepared with salt water (silica concentration:1.0% by mass, salt concentration: 229,000 ppm (salt water of high saltconcentration)) containing the aqueous sol of Example 1 (silica solcontaining silica particles subjected to surface treatment with3-glycidoxypropyltrimethoxysilane (GPS)) was injected from the pistoncylinder for nanoparticles and salt water, and carbon dioxide wasinjected from the CO₂ piston cylinder. The salt water-prepared liquidand carbon dioxide were simultaneously injected at a ratio of 1:1 at aflow rate of 4 feet/day into the carbonate rock (IN 200md) core samplesaturated with the crude oil in the core holder. For Comparative TestExample, only carbon dioxide was injected at a flow rate of 4 feet/dayinto the core sample saturated with the crude oil. The injection fluidwas injected into the core sample at 100° C., a back-pressure controlpressure of 200 atm, and a confining pressure (lateral pressure) of268.1 atm. The injection was performed until the volume of the injectionfluid reacted 120% relative to the pore volume of the core sample.

The crude oil recovery rate was calculated from the amount of the crudeoil recovered from the pores of the carbonate rock (IN 200md) coresample by the injection of the injection fluid (the aqueous sol ofExample 1, the salt water, and carbon dioxide) into the core sample. Theresults are shown in FIG. 19 and Table 9.

FIG. 19 and Table 9 show the amount of injection (the volume ratio ofthe injected fluid to the pores (injection volume/pore volume):PV) ofthe fluid (the aqueous sol of Example 1, the salt water, and carbondioxide) (corresponding to the horizontal axis), and the amount (%) ofthe crude oil recovered from the pores of the carbonate rock (IN 200md)core sample (corresponding to the vertical axis) when the total rockpore volume of the core sample is taken as 1.0. In FIG. 19 , the symbol“●” corresponds to the results of simultaneous injection of the saltwater (salt concentration: 229,000 ppm) containing the aqueous sol ofExample 1 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltrimethoxysilane (GPS)) and carbondioxide at a ratio of 1:1 at a flow rate of 4 feet/day, and the symbol“◯” corresponds to the results of injection of only carbon dioxide at aflow rate of 4 feet/day.

As shown in FIG. 19 and Table 9, when the amount of injection of thefluid into the pores of the carbonate rock (IN 200md) core samplereached 1.20 (120%), the crude oil recovery rate was 51.4% in the caseof injection of the aqueous sol of Example 1, the salt water, and carbondioxide, and the crude oil recovery rate was 37.0% in the case ofinjection of only carbon dioxide.

TABLE 9 Carbonate Rock (IN 200 md) Core Sample, Crude Oil Recovery RateComparative Example Example 1 Volume ratio CO₂ Volume ratio CO₂ foam ofinjected Crude oil of injected Crude oil fluid to pores: recovery ratefluid to pores: recovery rate PV (%) PV (%) 0.00 0.0 0.00 0.0 0.10 5.70.06 4.4 0.22 12.5 0.18 14.0 0.34 21.1 0.30 23.1 0.47 26.8 0.43 31.20.59 31.0 0.55 34.3 0.71 32.7 0.67 37.4 0.83 34.3 0.80 40.4 0.96 35.50.92 44.2 1.08 36.4 1.04 48.5 1.20 37.0 1.20 51.4

Test Example 3: Test for Determining Presence of Rock Core Pore Blockageby Aqueous Sol (Example 1) Using Sandstone (BSS)

The aqueous sol of Example 1 was used to prepare a sample having amedium salt concentration (175,000 ppm), a silica concentration of 1.0%by mass, and a pH of 6.3 in the same manner as described in [Salt WaterStability Test]. The sample was stored at 80° C. for seven days, andthen the sample was tested for determining whether or not it blockspores of a rock core.

FIG. 20(a) shows a sample (using the aqueous sol of Example 1) used inthe present test. It was visually confirmed that the silica particles ofthe aqueous sol dispersed uniformly and did not precipitate.

The aqueous sol prepared through the procedure of Example 1 as describedabove was added to salt water (medium salt concentration (175,000 ppm,pH 6.3)) so as to achieve a silica concentration of 1.0% by mass, andthe mixture was stored at 80° C. for seven days, to prepare a sample.Through the procedure described below, a test for determining presenceof rock core pore blockage (assuming subsurface oil reservoir) wasperformed by using the core pore blockage test apparatus (pipe andequipment layout) shown in FIG. 21 and using a rock core sample(sandstone, BSS-4) saturated with the sample and distilled water.

As shown in FIG. 21 , the core flow test apparatus includes injectionpumps (available from Schlumberger), a CO₂ piston cylinder for fluidcharging, a piston cylinder for nanoparticles and salt water, and adistilled water piston cylinder (available from VINCI Technologies), acore holder (available from VINCI Technologies), a confining pressurepump (available from VINDUM ENGINEERING), a back pressure valve and aback pressure pump (available from VINCI Technologies), a gas-liquidseparator for a recovered fluid (available from VINCI Technologies), awet gas meter for measuring the amount of free gas (available fromShinagawa Corporation), a pressure transducer (available from VALCOM), aresistance thermometer bulb for measuring a core temperature, athermostatic chamber temperature, and a free gas temperature (availablefrom Chino Corporation), and an air thermostatic chamber (available fromSunaka Rika Kogyo K. K.). The upstream and downstream pressures of thecore holder, the confining pressure (lateral pressure) of the coreholder, the pressure for control of the back pressure valve, thetemperatures of the core and the thermostatic chamber, and the amountand temperature of the free gas were recorded every second by a computervia a data logger (available from GRAPHTEC).

Test Example 3: Test for Determining Presence of Rock Core Pore Blockageby Aqueous Sol (Examples 1 and 2) Using Sandstone (BSS)

A sandstone (BSS) core sample (one sample) inserted in a rubber sleevewas placed in the core holder shown in FIG. 21 , and the pores of thesandstone (BSS) core were vacuumed, followed by vacuuming of the annularspace between the rubber sleeve and the inner wall of the core holder(annular space for fluid charging by confining pressure (lateralpressure)). After the annular space was saturated with a pressurizedfluid from the confining pressure pump by atmospheric pressure suction,the confining pressure (lateral pressure) was increased to 68.0 atm withthe confining pressure pump, to thereby determine that there is noleakage into the pores of the sandstone (BSS) core and to the exterior.The back pressure valve was set to 200 atm (i.e., test conditions) withthe back pressure pump. The injection pump 2 was connected to thedistilled water piston cylinder, and distilled water was introduced intothe vacuumed pores of the sandstone (BSS) core, followed bypressurization to 34.0 atm and control of the pump at constant pressure.In order to achieve the differential pressure set for the blockageevaluation test (back-pressure setting pressure+68.0 atm (1,000 psi)),the confining pressure (lateral pressure) was increased to 102.0 atm,and the amount of the introduced distilled water was recorded. Thepreliminarily measured dead volume between the upstream and downstreamvalves of the core holder was subtracted from the amount of theintroduced distilled water at a differential pressure of 68.0 atm, tothereby determine the 100% distilled water saturation volume of the corepores, which was used as the core pore volume for calculation of theamount of injection (the volume ratio of the injected fluid to the pores(injection volume/pore volume):PV). While determining that there is noleakage, the confining pressure (lateral pressure) and then the pressurein the core pores were increased in increments of 34.0 atm, and theconfining pressure (lateral pressure) and the pressure in the core poreswere set to 268.1 atm and 200.0 atm (test pressures), respectively. Theinjection pump 2 was set to constant flow rate control, and thedistilled water was injected at a low flow rate, to thereby determinethe operation of the back pressure valve and the signal output status ofthe pressure transducer. The upstream valve of the distilled waterpiston cylinder was closed, and the internal pressure of the pistoncylinder for fluid charging was controlled at a constant pressure of 200atm by the injection pumps 1 and 2. The air thermostatic chamber washeated from room temperature in increments of 10° C., and thetemperature of the air thermostatic chamber was maintained at 100° C.(test temperature). Regarding the fluid expansion volume during anincrease in temperature, the internal pressure of the piston cylinderfor fluid charging was maintained at 200 atm by the injection pumps 1and 2, the distilled water in the core holder was discharged from theback pressure valve and maintained at 200 atm, and the confiningpressure (lateral pressure) was maintained at 268.1 atm by the confiningpressure pump.

Subsequently, the liquid prepared with salt water (silica concentration:1.0% by mass, salt concentration: 175,000 ppm (salt water of medium saltconcentration)) containing the aqueous sol of Example 1 (silica solcontaining silica particles subjected to surface treatment with3-glycidoxypropyltrimethoxysilane (GPS)) was injected from the pistoncylinder for nanoparticles and salt water, and carbon dioxide wasinjected from the CO₂ piston cylinder. The salt water-prepared liquidand carbon dioxide were simultaneously injected at a ratio of 1:1 at aflow rate of 4 feet/day into the sandstone (BSS) core sample saturatedwith the distilled water in the core holder. The injection fluid wasinjected into the core sample at 100° C., a back-pressure controlpressure of 200 atm, and a confining pressure (lateral pressure) of268.1 atm. While the injection differential pressure (fluid flowdifferential pressure at a flow rate of 4 feet/day) was measured, theinjection process was continued until completion of injection of theentire amount of the liquid prepared with salt water (silicaconcentration: 1.0% by mass, salt concentration: 175,000 ppm (salt waterof medium salt concentration)) containing the aqueous sol of Example 1(silica sol containing silica particles subjected to surface treatmentwith 3-glycidoxypropyltrimethoxysilane (GPS)) charged in the pistoncylinder and automatic stop of the injection pump 2 in association withan increase in the pressure of the pump 2 to 234 atm (i.e., upper limitsetting value of pump pressure). When the fluid flows out of the backpressure valve and the differential pressure decreases to 0 atm (theupstream pressure of the sandstone (BSS) core sample−the downstreampressure thereof) after completion of the injection, the core isdetermined not to be blocked, whereas when the differential pressure ismaintained at 234 atm (i.e., upper limit setting value of pump pressure)(the upstream pressure of the sandstone (BSS) core sample−the downstreampressure thereof) after completion of the injection, the core isdetermined to be blocked. When the core is determined not to be blocked,and the injection differential pressure increases upon simultaneousinjection of the salt water-prepared liquid from the piston cylinder fornanoparticles and salt water and carbon dioxide from the CO₂ pistoncylinder at a ratio of 1:1, the apparent viscosity of the injectionfluid is suggested to be increased, and CO₂ foam is expected to beformed.

The injection differential pressure of the fluid flowed through thepores of the sandstone (BSS) core sample by the injection of theinjection fluid (the aqueous sol of Example 1, the salt water, andcarbon dioxide) into the core sample was measured. The results are shownin FIG. 22 and Table 10.

The term “injection differential pressure” as used herein refers to thedifference between the primary pressure (upstream pressure) and thesecondary pressure (downstream pressure) during flow of the fluid. Inthe flow test, the injection differential pressure corresponds to thedifference between the pressures measured on the upstream and downstreamsides of the core sample inserted in the core holder during flow of thefluid (i.e., injection (flow) differential pressure=the upstreampressure−the downstream pressure). When the injection flow rate isconstant, the injection differential pressure is low in a core of highpermeability, and the injection differential pressure is higher in acore of low permeability. In the case of a single core (i.e., constantpermeability), high injection flow rate of a fluid leads to highdifferential pressure, and low injection flow rate leads to lowdifferential pressure. In the case of a constant flow rate, injection ofa fluid of high viscosity leads to high differential pressure, andinjection of a fluid of low viscosity leads to low differentialpressure.

FIG. 22 shows the amount of injection (the volume ratio of the injectedfluid to the pores (injection volume/pore volume):PV) of the fluid(sample prepared by storage (at 80° C. for seven days) of the salt water(silica concentration: 1.0% by mass, salt concentration: 175,000 ppm(salt water of medium salt concentration)) containing the aqueous sol ofExample 1 (silica sol containing silica particles subjected to surfacetreatment with 3-glycidoxypropyltrimethoxysilane (GPS)), carbon dioxide)(corresponding to the horizontal axis), and the injection differentialpressure (corresponding to the left vertical axis) and the amount (cc)of the salt water (containing the aqueous sol) recovered from the poresof the sandstone (BSS) core sample (corresponding to the right verticalaxis) when the total rock pore volume of the core sample is taken as1.0. In FIG. 22 , the symbol “●” corresponds to the injectiondifferential pressure, and the symbol “◯” corresponds to the amount ofthe recovered liquid.

As shown in Table 10 and FIG. 22 , an increase in the injectiondifferential pressure suggested the formation of froth or emulsion inthe interior of the rock core. Since the upstream pressure was reducedto the downstream pressure immediately after stop of the pump, and thedifferential pressure reached 0 atm, the core was determined not to be“blocked.” FIG. 23 is a photograph showing formation of froth in therecovered fluid. The aqueous sol of Example 2 (silica sol containingsilica particles subjected to surface treatment with3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane (PTMS))was also subjected to the test for determining presence of core blockageusing the sandstone (BSS). The results are shown in FIG. 24 and Table11.

FIG. 24 shows the injection time (hours) of the fluid (sample preparedby storage (at 80° C. for seven days) of the salt water (silicaconcentration: 1.0% by mass, salt concentration: 175,000 ppm (salt waterof medium salt concentration)) containing the aqueous sol of Example 2(silica sol containing silica particles subjected to surface treatmentwith 3-aminopropyltriethoxysilane (APTES) and phenyltrimethoxysilane(PTMS)), carbon dioxide) (corresponding to the horizontal axis), and theinjection differential pressure (corresponding to the vertical axis)when the total rock pore volume of the sandstone (BSS) core sample istaken as 1.0.

As shown in Table 11 and FIG. 24 , a gradual increase in the injectiondifferential pressure applied to the sandstone core was determined afterinitiation of the fluid injection. 5.42 Hours after initiation of thefluid injection, the experimental operation was terminated; i.e., theinjection was terminated by stop of the pump. Thereafter, a gradualdecrease in the differential pressure applied to the sandstone core wasdetermined. A gradual decrease in the pressure was determinedimmediately after stop of the pump before the differential pressurereached 0 atm. Such “mild blockage” caused no problem in practice.

TABLE 10 Sandstone (BSS) Core Sample/Test for Determining Presence ofRock Core Blockage (Example 1) Volume ratio Injection Amount of ofinjected differential recovered fluid to pores pressure liquid (PV)(atm) (cc) 0.00 0.0 0.00 0.65 2.7 16.20 1.30 5.7 45.70 2.59 7.8 88.953.89 9.3 142.00 5.18 11.4 183.75 6.48 14.4 224.00 7.77 18.7 264.00 9.0727.6 304.25 10.36 35.8 343.00 10.36 0.0 —

TABLE 11 Sandstone (BSS) Core Sample/Test for Determining Presence ofSandstone Core Blockage (Example 2)/ Piston Cylinder Injection Pump ofSalt Water Containing Silica Nanoparticles/Transition of Pressure FluidInjection Fluid Injection Injection differential Injection differentialtime pressure time pressure (hours) (atm) (hours) (atm) 0.00 0.3 4.523.8 0.12 0.4 5.12 4.1 0.32 0.4 5.32 4.4 0.52 0.3 5.42 3.1 1.12 0.6 5.521.9 1.32 0.6 6.02 1.2 1.52 1.1 6.12 1.0 2.12 1.1 6.22 1.1 2.32 1.3 6.320.0 2.52 1.8 6.42 0.0 3.05 1.9 6.52 0.0 3.12 2.0 7.02 0.0 3.32 1.8 7.120.0 3.52 2.5 7.22 0.0 4.12 3.1 7.32 0.0 4.32 3.1 7.42 0.0

Test Example 4: Test for Determining Presence of Rock Core Pore Blockageby Aqueous Sol (Comparative Example 1) Using Sandstone (BSS)

The aqueous sol of Comparative Example 1 was used to prepare a samplehaving a medium salt concentration (175,000 ppm), a silica concentrationof 1.0% by mass, and a pH of 7.2 in the same manner as described in[Salt Water Stability Test]. The sample was stored at 80° C. for sevendays, and then the sample was tested for determining whether or not itblocks pores of a rock core.

FIG. 20(b) shows a sample (using the aqueous sol of ComparativeExample 1) used in the present test. It was visually confirmed that thesilica particles of the aqueous sol aggregated and precipitated.

The aqueous sol prepared through the procedure of Comparative Example 1as described above was added to salt water (medium salt concentration(175,000 ppm, pH 7.2)) so as to achieve a silica concentration of 1.0%by mass, and the mixture was stored at 80° C. for seven days, to preparea sample. Through the same procedure as described in Test Example 3, atest for determining presence of rock core pore blockage (assumingsubsurface oil reservoir) was performed by using the core pore blockagetest apparatus (pipe and equipment layout) shown in FIG. 21 and using arock core sample (sandstone, BSS-5) saturated with the sample anddistilled water.

FIG. 25 shows the amount of injection (the volume ratio of the injectedfluid to the pores (injection volume/pore volume):PV) of the fluid(sample prepared by storage (at 80° C. for seven days) of the salt water(silica concentration: 1.0% by mass, salt concentration: 175,000 ppm(salt water of medium salt concentration)) containing the aqueous sol ofComparative Example 1, carbon dioxide) (corresponding to the horizontalaxis), and the injection differential pressure (corresponding to theleft vertical axis) and the amount (cc) of the salt water (since anincrease in the injection differential pressure was not measured and thedifferential pressure varied within a range of about 2 to 3 atm, it wasassumed that the silica particles of the aqueous sol aggregated andprecipitated in the piston cylinder for nanoparticles and salt water,and only the salt water was injected) recovered from the pores of thesandstone (BSS) core sample (corresponding to the right vertical axis)when the total rock pore volume of the core sample is taken as 1.0. InFIG. 25 , the symbol “●” corresponds to the injection differentialpressure, and the symbol “◯” corresponds to the amount of the recoveredliquid.

TABLE 12 Sandstone (BSS) Core Sample/Test for Determining Presence ofRock Core Blockage (1) (Comparative Example 1) Volume ratio InjectionAmount of of injected differential recovered fluid to pores pressureliquid (PV) (atm) (cc) 0.00 0.0 0.00 0.67 2.8 32.50 2.00 1.8 76.50 3.331.9 116.75 4.67 1.5 156.75 6.00 1.6 196.75 7.33 1.3 237.25 8.66 1.6277.25 10.00 1.4 317.25 11.33 1.2 357.25 12.00 0.9 391.00 12.66 0.7429.00 13.33 0.6 458.50

As shown in Table 12 and FIG. 25 , an increase in the injectiondifferential pressure, which indicates formation of froth or emulsion inthe interior of the rock core, was not measured.

The reason for this is probably attributed to the fact that the saltwater containing the aqueous sol (Comparative Example 1) causedseparation and precipitation of the silica component of the aqueous solin the interior of the charged piston cylinder, and the silica componentof the salt water containing the aqueous sol of Comparative Example 1was gelatinized, whereby the silica component of the salt watercontaining the aqueous sol of Comparative Example 1 was not injectedinto the rock core sample. The aforementioned term “gelatinized”represents formation of gelatin composed of silica.

Thereafter, the injection was further continued, and as a result, asudden increase in pressure was measured as shown in Table 13 (FIG. 26). FIG. 26 shows the fluid injection pressure (vertical axis) withrespect to the injection time (horizontal axis). The results shown inTable 13 and FIG. 26 suggest that the silica component of thegelatinized aqueous sol (Comparative Example 1) started to be injected,as an injection fluid, into the pores of the rock core sample at thetime when a sudden increase in pressure (after the elapse of 4.06 hours)was determined, but “blockage” of the pores occurred immediately afterthe start of the injection of gelatinized silica.

TABLE 13 Sandstone (BSS) Core Sample (Comparative Example 1)/ Test forDetermining Presence of Rock Core Blockage (2)/ Piston CylinderInjection Pump for Salt Water Containing Silica Nanoparticles/Transitionof Pressure Injection Injection pump, time Transition of pressure(hours) (atm) 0.00 201.6 0.33 204.7 0.67 203.9 1.01 203.5 1.35 203.61.69 203.7 2.03 203.6 2.37 203.5 2.71 203.6 3.05 203.2 3.38 203.1 3.72203.0 4.06 240.5 4.15 240.5 4.24 240.7 4.32 240.6 4.41 240.8 4.49 240.84.57 240.9 4.66 240.7 4.74 240.8

FIG. 27 is a photograph showing the gelatinized silica component of theaqueous sol (Comparative Example 1) in the cylinder for the injectionfluid, which was visually observed during dismantling of the blockagetest apparatus (room temperature) after completion of the test performedby using the aqueous sol of Comparative Example 1. As shown in FIG. 27 ,the silica component of the aqueous sol (Comparative Example 1) can bedetermined to be gelatinized, which indicates that the aqueous solfailed to be injected into the rock core.

In the case of such gelatinization, the aqueous sol cannot be injectedin the interior of the rock, and the gelatinization is likely to causetotal loss of the permeability of the rock itself. However, as shown inthe differential pressure behavior of the APTES-type aqueous sol ofExample 2 (FIG. 24 , Table 11), when blockage is mild enough not toresult in total loss of the permeability, there is room to expect thatthe flow path of the injected fluid (CO₂ or CO₂ foam) can be changed inthe rock to thereby improve the displacement efficiency.

The invention claimed is:
 1. A crude oil recovery method for recoveringcrude oil from a subsurface hydrocarbon-containing reservoir, the methodcomprising: step (a): injecting an aqueous sol, water and carbondioxide, each alternatingly or simultaneously, into a subsurface oilreservoir; wherein the aqueous sol comprises silica particles having anaverage particle diameter of 1 to 100 nm as measured by dynamic lightscattering and having surfaces at least partially coated with a silanecompound having a hydrolyzable group, wherein the hydrolyzable group isselected from the group consisting of an alkoxy group, an acyloxy group,and a halogen group, the silica particles serving as a dispersoid andbeing dispersed in an aqueous solvent having a pH of 1.0 or more to 6.0or less serving as a dispersion medium; and step (b): following theinjecting, recovering oil extracted by an oil production well drilledinto the subsurface oil reservoir.
 2. The crude oil recovery methodaccording to claim 1, wherein the step (a) is a step of injecting theaqueous sol and water, and carbon dioxide alternatingly into thesubsurface oil reservoir.
 3. The crude oil recovery method according toclaim 1, wherein the injection in the step (a) is performed at atemperature of 30 to 120° C. and a pressure of 70 to 400 atm.
 4. Thecrude oil recovery method according to claim 1, wherein the subsurfaceoil reservoir contains sandstone.
 5. The crude oil recovery methodaccording to claim 1, wherein the subsurface oil reservoir containscarbonate rocks.
 6. The crude oil recovery method according to claim 1,wherein the silane compound having the hydrolyzable group is selectedfrom the group consisting of 3-glycidoxypropyltrimethoxysilane,3-glycidoxypropyltriethoxysilane,3-glycidoxypropylmethyldimethoxysilane,3-glycidoxypropylmethyldiethoxysilane,3-(3,4-epoxycyclohexyl)propyltrimethoxysilane,3-(3,4-epoxycyclohexyl)propyltriethoxysilane,2-(3,4-epoxycyclohexyl)ethyltrimethoxysilane,2-(3,4-epoxycyclohexyl)ethyltriethoxysilane,1-(3,4-epoxycyclohexyl)methyltrimethoxysilane,1-(3,4-epoxycyclohexyl)methyltriethoxysilane,[(3-ethyl-3-oxetanyl)methoxy]propyltrimethoxysilane and[(3-ethyl-3-oxetanyl)methoxy]propyltriethoxysilane,N-2-(aminoethyl)-3-aminopropylmethyldimethoxysilane,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane,3-aminopropyltrichlorosilane, 3-aminopropyltrimethoxysilane,3-aminopropyltriethoxysilane, 3-aminopropylmethyldimethoxysilane,3-aminopropylmethyldiethoxysilane,3-triethoxysilyl-N-(1,3-dimethyl-butylidene)propylamine,N-phenyl-3-aminopropyltrimethoxysilane, andN-phenyl-3-aminopropyltriethoxysilane.
 7. The crude oil recovery methodaccording to claim 1, wherein the silane compound having a hydrolyzablegroup is a silane compound having, in addition to the hydrolyzablegroup, an epoxy group or an organic group produced by hydrolysis of theepoxy group.
 8. The crude oil recovery method according to claim 7,wherein the epoxy group is a glycidyl group, a cyclohexylepoxy group, ora combination of these.
 9. The crude oil recovery method according toclaim 1, wherein the silane compound having a hydrolyzable group is asilane compound having, in addition to the hydrolyzable group, an aminogroup.
 10. The crude oil recovery method according to claim 1, whereinthe silane compound having a hydrolyzable group further contains asecond silane compound having a hydrolyzable group.
 11. The crude oilrecovery method according to claim 10, wherein the second silanecompound having a hydrolyzable group is a silane compound having anorganic group containing a C₁₋₄₀ alkyl group, a C₆₋₄₀ aromatic ringgroup, or a combination of these.